Course holding method and apparatus for rotary mode steerable motor drilling

ABSTRACT

A drilling machine for a wellbore is provided. The drilling machine may include one or more dynamic lateral pads (or simply “pads”) that are movable between an extended and retracted position. Generally, the pad(s) are deployed on the bend side of the drilling machine proximal to the drill bit and distal of the bend of the housing. While drilling, the drill bit may experience a deviation force that causes the drill bit to become misaligned with its original course. By extending the pad(s), however, the drilling machine can counteract the deviation force. Deployment of the pad(s) can produce a restorative force in opposition to the deviation force, thereby reducing or eliminating the directional tendency resulting from the deviation force.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 15/430,254 filed on Feb. 10, 2017, which claimspriority to U.S. Provisional Patent Application No. 62/295,904 filedFeb. 16, 2016, each of which is incorporated herein by reference as ifset out in full.

The present application is also related to U.S. patent application Ser.No. 16/049,588 filed on Jul. 30, 2018, U.S. patent application Ser. No.15/667,704 filed on Aug. 3, 2017, and U.S. patent application Ser. No.15/808,798 filed on Nov. 9, 2017, each of which is incorporated hereinby reference as if set out in full.

BACKGROUND

Hydrocarbon retorts for the most part reside beneath a surface layer ofdirt and rock (and sometimes water as well). Thus, companies generallyerect drilling rigs and drill piping from the surface to a point locatedbelow the surface to allow access and retrieval of the hydrocarbons fromthe retorts.

Drilling may comprise vertical wells, non-vertical wells, andcombinations thereof. Vertical wells provide a reasonably straight drillpath that is generally intended to be perpendicular to the earth'ssurface, and the drill bit is operational along the axis of the drillstring to which it is attached. Non-vertical wells, also known asdirectional wells, usually involve directional drilling. Directionallydrilling a well requires movement of the drill bit off the axis of thedrill string. Generally, a directionally drilled wellbore includes avertical section until a kickoff point where the wellbore deviates fromvertical.

To directional drill, most operations use a motor steerable system orrotary steerable tool (sometimes referred to as RST or RSS). Both toolsare useful because they allow for directional drilling (moving fromvertical to horizontal in some cases), but also provide for a tool thatgenerally travels in a straight path as well. A conventional RSS cangenerally be classified as a point the bit architecture or a push thebit architecture. A point the bit architecture generally flexes theshaft attached to the bit, to cause the bit to point in a differentdirection. The GEO-PILOT® rotary steerable system available fromHalliburton Company is an exemplary point the bit architecture. A pushthe bit architecture generally has one or more pads on the outer surfaceof the rotating drill string housing. The pads press on the wellbore tocause the drill bit to move in the opposite direction causing adirectional change in the wellbore. The AutoTrak Curve rotary steerablesystem, available from Baker Hughes Incorporated, is an exemplary pushthe bit architecture. Many companies offer steerable motors thatincorporate a bent housing within its architecture that must be orientedin the desired position to generate the required directional change. Thedrill string that connects this assembly and bit to the rig floor mustremain essentially stationary during the drilling of these directionalchange segments. Various RSS tool offerings have no non-rotationalrequirements or segments that need to be stationary while other RSSdesigns incorporate certain sections of the tool that must remainstationary or only rotate at a very slow speed.

FIG. 1, for background, shows a conventional steerable motor system 10that is part of drill string 12 that extends from the surface, at themost proximal end 50, and terminates in drill bit 14 at distal end 52.Conventionally, as drill string 12 rotates as shown by arrow R and mudflow through steerable motor 16 adds rotation to bit 14, the steerablemotor system drills in a generally straight line. The drilling path maybe vertical or angled (generally between 0 to 90 degrees, but in someinstances, up to 180 degrees with respect to vertical) depending on thedrill plan. Once drill string 12 has deviated from vertical, a well boredirection is established and is typically measured, like a compass, as amagnetic heading or azimuth (ranging from 0 to 360 degrees). Whensteerable motor system 10 is being manipulated to directionally drill(by which directional or directionally drilling generally meansmodifying the angle of inclination and/or azimuth of the hole), wherethe rate of change is typically measured in degrees over a distance(generally degrees per 100 feet or degrees per 30 meters), rotation ofdrill string 12 from the surface is normally halted to facilitatedirectional change. As is well known in the art, one drawback of aconventional steerable system 10, is that cessation of rotation maycause friction to turn from dynamic to static resulting in anundesirable increase in friction between drill string 12, includingsteerable motor 16, and the wellbore (not shown).

In any event, drill string 12 includes a number of segments, not all ofwhich are shown in FIG. 1, including drill piping or tubulars 26 to thesurface, steerable motor 16 and drill bit 14. Steerable motor 16generally comprises rotor catch assembly 18, power section 20,transmission 22, bearing package 24, and bit drive shaft 46 with bit box34. Power section 20 generally comprises stator housing 28 connected toand part of drill string 12, and rotor 30. Transmission 22 includestransmission housing 36, that is part of drill string 12, andtransmission driveline 38 that connects rotor 30 to bit drive shaft 46.Bearing package 24 includes bearing housing 42, part of the drillstring, and one or more bearing assemblies 44 that may include differentcombinations of axial, radial, and thrust bearings. Transmission housing36 generally includes bend 35 to modify drill bit 14 angular rotationaxis B relative to drill string 12 rotation axis A, generally a bend isfrom around 0.5 to 5.0 degrees. (The modification of the angular axis ofrotation is more thoroughly described below and is well-documented art.)Because the magnitude of bend 35 can be visually relatively small, thedirection of the bend plane is generally marked by a shallowlongitudinal groove called scribe line 40.

With mud flow, drilling mud (not shown) travels down internal cavities32 of drill string 12 and through power section 20 causing rotor 30 torotate with respect to stator housing 28 and therefore drill string 12.Rotor 30 drives rotation through transmission driveline 38 and bit driveshaft 46, to drill bit 14. Depending on the rotation direction(clockwise or counter clockwise) of rotor 30 relative to drill string12, power section 20 can increase, decrease or reverse the relativerotation rate of drill bit 14 with respect to a rotating drill string12. During drilling operations with a conventional steerable motorassembly 10, when it is determined to be desirable to modify thetrajectory (angle of inclination and azimuth) of the wellbore, rotationof drill string 12 is terminated while maintaining mud flow throughmotor power section 20 and therefore continuing rotation of drill bit14. By one of many methods that are well known and regularly practicedin the industry (such as MWD tools, LWD tools, drilling gyro tool andwireline orienting tool), the current orientation of drill bit 14 isdetermined. Drill string 12 is then manually oriented from the surface,generally by fractions of a full rotation, until scribe line 40 (andtherefore bit 14) is oriented in the desired direction. Thus, thewellbore direction is altered in the direction of the scribe line 40 bythe continued rotation of the drill bit 14 via the steerable motor 16while the drill string 12 is not rotating. As the well continues to bedrilled, the orientation of the scribe line 40 is continually monitoredand adjusted to create the desired wellbore path. The adjustment of thescribe line 40 conventionally includes manual orientation of the drillstring to keep the scribe line 40 oriented in the desired direction. Thedetails of conventional steerable motor system 10 are reasonably wellknown in the industry and will not be further explained except asnecessary to understand the technology of the present application.

Drill bit 14 conventionally can be a number of different styles or typesof drill bits. Drill bit 14 may be a polycrystalline diamond cutter(PDC) design, a roller cone (RC) design, an impregnated diamond design,a natural diamond cutter (NDC) design, a thermally stablepolycrystalline (TSP) design, a carbide blade/pick design, a hammer bit(a.k.a. percussion bits) design, etc. Each of these different rockdestruction mechanisms has qualities that make it a desirable choicedepending on formation to be drilled and available energy in associationwith the drilling apparatus.

For a variety of disparate reasons, drill bit technology integratedwithin a drilling apparatus or drilling machine methodology could usemuch improvement, whether implemented in a vertical drilling system orincorporated into a Steerable Motor or RSS usable with directionaldrilling. Thus, against the above background, improved drill bitsseparately or as part of an integrated drilling apparatus or machinecoordinated with drill string components, are further described herein.

SUMMARY

This Summary is provided to introduce a selection of concepts in asimplified form that are further described below in the DetailedDescription. This Summary, and the foregoing Background, is not intendedto identify all key aspects or essential aspects of the claimed subjectmatter. Moreover, this Summary is not intended for use as an aid inlimiting the scope of the claimed subject matter.

In some aspects of the technology, a downhole drilling apparatus ormachine is provided. The drilling apparatus or machine comprises a drillbit or cutting structure assembly having a pad that can extend generallyperpendicularly to the bit axis by a variable amount from a minimumdistance to a maximum distance where the minimum distance is flush orrecessed with an axial sidewall of the drill bit or drill string. In theextended position, the pad has a surface that is configured to engagethe sidewall of a wellbore. The drilling apparatus may include anactuator to move the pad between the extended position and the retractedposition. In certain aspects, the actuator is a push rod or cam followerdriven by a cam. The actuator can provide a solid/positive transfer offorce or the actuator can provide compliant transfer of force to limittravel, force or both. In other aspects, the actuator is a cam. In stillother aspects, the actuator can be magnets configured to attract orrepel depending on proximity and magnetic pole orientation. The push rodmay include a taper such that the pad is positionable at a plurality ofpositions between the maximum extension in the extended position and theminimum position in the retracted position. The drill bit or cuttingstructure assembly comprises a plurality of cutting elements. Whenextended, the pad is configured to push against the sidewall and movethe drill bit and cutting elements in an opposing direction.

In certain embodiments, the drill bit may include at least one lateralcutting apparatus located on a side of the drilling apparatus. At leastone lateral cutting apparatus would generally engage the sidewall of awellbore and remove formation at least when the pad is in the extendedposition. As a result of the added force of the lateral pad or pads, theopposing cutting structure design could have a variable position designor an enhanced fixed cutter design to assist in the directional changecapacity.

In certain aspects, the drilling apparatus comprises a plurality ofpads, wherein each of the plurality of pads is operatively coupled to atleast one actuator such that as the plurality of pads are configured torotate with the drill bit or configured to rotate with the drill stringthat is generally not rotating while directionally drilling. Theactuator may be configured to move each of the plurality of pads fromthe retracted position to the extended position wherein a maximumextension occurs at a position generally opposite a minimum extension.

In certain aspects, the pad begins moving from a retracted position toan maximum extended position and back to a retracted position as the padrotates about a longitudinal axis of the drilling apparatus. The pad maybegin extending and retracting at virtually any angle such as about 30,45, 90, or 135 degrees and be fully retracted at a corresponding 330,315, 270, 225 degrees of rotation providing generally symmetricoperation. Of course, the pad may begin extension at less than 15degrees of rotation and finish retracting at greater than 345 degrees ofrotation. In certain other embodiments, aspects relating to such thingsas drilling system design and formation properties may be betteroptimized using asymmetric operation modes where the pad may be beginextending at say 135 degrees and not be fully retracted until 330degrees of rotation. In certain embodiments, the pad may always beslightly extended. A further aspect provides for multiple full orpartial extensions and retractions of a pad or a plurality of padsduring each revolution to improve cutting effectiveness by providingmultiple cutter engagements to the well bore. Another embodiment wouldbe to extend a pad or pads off center of the cutter or cutters to modifythe cutter contact angle with the well bore.

In other embodiments, a downhole drilling apparatus to be attached to adrill string is provided. The apparatus has a drill bit having at leastone cutting element axially extending out to the sidewall and a drillbit having a plurality of cutting structures. A cutting pad isoperatively coupled to a recess formed in the outer sidewall of thedrill bit. A cutting element is coupled to an outwardly facing surfacesuch that at least when in the extended position, the cutting element isconfigured to engage a sidewall of a wellbore to remove formation.

In certain embodiments, and generally applicable with any drillingapparatus or drilling machine methodology using moveable pads to contactthe bore hole, the pad extension path can be axially rotated fromperpendicular (by around 2 to 45 degrees) to push the drill stringforward or better align the contact plane of the pad with the boreholewall to minimize pad pressure or both when extended. In certain aspects,the cam can include a conical profile such that an axially rotatedextension pad can be engaged with a cam race that is parallel with theplane of the pad to contact the borehole wall. A further aspect providesa pad path that is cross-axially offset to provide a side forcetemporarily across an opposing cutter face.

In certain embodiments, the technology of the present applicationprovides a drill string that includes a power section to providerotative force and a transmission that is operatively coupled to thepower section. A monolithic or integral drill bit/drive shaft consistsof a drill bit portion at a distal end and a drive shaft portion at aproximal end, wherein the transmission is operatively coupled to theproximal end of the monolithic or integral drill bit/drive shaft totransmit rotative force from the power section to the drill bit portion.The drill string may further include a bearing section and possibly abent housing section.

In some aspects of the technology, a downhole apparatus is provided thatcomprises at least a dual rotating cutting structure having variouscutting element types positioned on an inner assembly element and on aseparate outer cutting structure where the power source to rotate thetwo cutting structures can be independently derived. In almost allcases, the resultant rotation rate for each cutting structure would bedifferent. In those cases, where PDC cutters are used to form both theinternal and external cutting structures a lower rotation rate of theouter cutting structure can result in a matched or lower surface speedthan the internal cutting structure. This can extend the life of the PDCcutter by reducing and better controlling heat generation in theoutermost cutters. Additionally, having multiple PDC cutting structuresrotating at different rotation rates allows for designing a bettermechanical solution to fail (destroy rock) in distinct areas of theformation to be drilled.

In certain embodiments, a plurality of rotating cutting structures wouldbe associated with a bent housing above said rotating cutting structuresto support the efficient removal of the central area of the wellbore. Inthis configuration, the directional usefulness of the bent housing wouldnot be available unless it only supported a rotating directionaltendency of the assembly.

In certain other embodiments, the technology of the present inventionprovides a drill string that may include various sizes and shapes of mudmotors to accommodate reduced power requirements. The drill string mayfurther include a bearing section and transmission section sizedaccordingly to the reduced loads anticipated versus a standard singlebit/motor combination.

In some aspects of the technology, a downhole apparatus is provided thatemploys one or more motor mandrel cam-driven pads to provide arestoration force in opposition to the deviation force of the rotatingassembly. In certain embodiments, the pad(s) are deployed generally onthe bend side of the downhole apparatus proximal to the drill bit anddistal of the bend of the bend housing. The pad(s) may deploy andretract one or more times per motor (mandrel) revolution depending onthe mandrel cam configuration. In certain embodiments, the pad(s) areprovided with a stroke that pushes them out to a diameter substantiallyequal to, or slightly greater than, the bit diameter. In embodimentswhere the downhole apparatus is biased against the hole wall, the pad(s)can push against the hole wall with a greater force or frequency inopposition to the deviation bias direction providing a restorative forceto the downhole apparatus. The action of the pad(s) may counter thedeviation force, thereby reducing or eliminating the directionaltendency.

These and other aspects of the present system and method will beapparent after consideration of the Detailed Description and Drawingsherein.

DRAWINGS

Non-limiting and non-exhaustive embodiments of the present invention,including the preferred embodiment, are described with reference to thefollowing figures, wherein like reference numerals refer to like partsthroughout the various views unless otherwise specified.

FIG. 1 provides a cross-sectional view of a conventional steerable motorsystem.

FIG. 2 provides a cross-sectional view of a drilling assembly having adynamic lateral pad consistent with the technology of the presentapplication. FIG. 2 also includes a side view and isometric view of amonolithic or integral drill bit/drive shaft.

FIG. 3A provides a comparison between a conventional motor drill stringand an improved motor drill string having a monolithic or integralbit/drive shaft consistent with the technology of the present invention.

FIG. 3B provides a comparison between a conventional motor drill stringwith a bend and an improved motor drill string having a monolithic orintegral drill bit/drive shaft and bend consistent with the technologyof the present invention.

FIG. 4A provides a side view of a drill string with an axial cam andintegral drill bit/drive shaft consistent with the technology of thepresent application.

FIG. 4B provides a cross-section view of the drill string provided inFIG. 4A.

FIG. 4C provides a cross-section view of the drill string provided inFIG. 4A without a bend.

FIG. 5A provides a cross-sectional view of a drill string including adynamic lateral pad and sleeve cam consistent with the technology of thepresent application.

FIG. 5B provides a series of end views of the drill string provided inFIG. 5A showing bit rotation and pad movement at successive 90 degreerotation intervals.

FIG. 6 provides a cross-sectional view of a monolithic or integral drillbit/drive shaft having multiple dynamic lateral pads consistent with thetechnology of the present application.

FIG. 7 provides a cross-sectional view of a monolithic or integral drillbit/drive shaft having a dynamic lateral pad and bit shank camconsistent with the technology of the present application.

FIG. 8A provides a cross-sectional view of drill string 800 including amonolithic or integral drill bit/drive shaft, a plurality of DynamicLateral Pads (DLPs), a plurality of Dynamic Lateral Cutters and sleevecam consistent with the technology of the present application.

FIG. 8B provides an end view of the drill string provided in FIG. 8Aillustrating an odd number of blades, cutters and pads consistent withthe technology of the present application.

FIG. 9 provides a series of alternative embodiments for dynamic lateralpad and dynamic lateral cutter mechanisms.

FIG. 10A provides a side-by-side partial section view of a Dual RotatingCutting Structure (DRCS) system, with and without a bend, consistentwith the technology of the present application.

FIG. 10B provides an enlarged side view of the dual rotating cuttingstructure portion of FIG. 10A.

FIG. 10C provides a cross-sectional view of Dual Rotating CuttingStructure (DRCS) system with a protruding inner drill bit or innercutting structure as provided in FIG. 10B, consistent with thetechnology of the present application.

FIG. 11 provides a cross-sectional view of a Dual Rotating CuttingStructure (DRCS) system with a substantially flush inner drill bit orinner cutting structure consistent with the technology of the presentapplication.

FIG. 12 provides a cross-sectional view of a Dual Rotating CuttingSystem (DRCS) with a recessed inner drill bit or inner cutting structureconsistent with the technology of the present application.

FIG. 13 provides a cross-sectional view of a Dynamic Lateral Pad (DLP)system with a bit box cam, hinged circumferential pad and compliantactuator consistent with the technology of the present application andalso including an isometric view and side view with multiple compliantactuator in various positions.

FIG. 14 provides a cross-section view of a Dynamic Lateral Pad (DLP)system with magnetic actuators consistent with the technology of thepresent application with an extended pad. In addition, FIG. 14 providesan isometric view, and a side view with the pad retracted and a sectionview of the magnetic actuator.

FIG. 15 provides a cross-sectional and isometric view of a DynamicLateral Pad (DLP) system with a bit box cam, axially hinged pad andsolid actuator consistent with the technology of the presentapplication.

FIG. 16A provides a cross-sectional view of a bit mounted DynamicLateral Pad (DLP) with a sleeve cam with an extended pad consistent withthe technology of the present application. In addition, FIG. 16Aprovides an isometric view and a section view of a retracted pad.

FIG. 16B provides a cross-sectional view of a bit mounted DynamicLateral Pad (DLP) and Dynamic Lateral Cutter (DLC) with sleeve cam andan extended pad with cutters consistent with the technology of thepresent application. In addition, FIG. 16B provides an isometric viewand a section view of a retracted pad with cutters.

FIG. 17 provides a cross-sectional view of a dynamic bit blade withsleeve cam and an extended blade consistent with the technology of thepresent application. In addition, FIG. 17 includes an isometric view anda section view of a retracted blade.

FIG. 18 provides a cross-sectional view of an eccentric bearing housingwith pockets consistent with the technology of the present application.In addition, FIG. 18 includes an isometric view, an end view and asection view of the eccentric bearing housing and a covered pocket.

FIG. 19A-H provide views of several exemplary embodiments of drill bitand drill string sections incorporating technology consistent with thedisclosure of the present application.

FIG. 20 provides a typical tool face angle chart or dial.

FIG. 21A provides a cross-sectional view of an oversized rotary drilledhole at the locations of a rotating bit gauge circumference.

FIG. 21B provides a detailed view of the cross-sectional hole centershown in FIG. 21A in neutral drilling mode.

FIG. 21C provides a detailed view of the cross-sectional hole centershown in FIG. 21A experiencing a deviation bias.

FIG. 22 provides a generalized and exaggerated comparative side view ofa neutral drilling borehole and a drop deviation borehole.

FIG. 23 provides a generalized and exaggerated comparative side view ofa neutral drilling borehole and a left turn deviation borehole.

FIG. 24 provides an end view of a neutral drilling borehole.

FIG. 25 provides an end view of a deviated dropping and left turningborehole.

FIG. 26A provides an isometric view of a partial section of a basicDynamic Lateral Pad (DLP) assembly consistent with the technology of thepresent application.

FIG. 26B provides a cross-sectional view of a Dynamic Lateral Pad (DLP)assembly taken through section A-A of FIG. 26A.

FIG. 27A provides a cross-sectional view of an oversized rotary drilledhole at the location of a rotated cross-section of a deployed DynamicLateral Pad (DLP) during neutral drilling consistent with the technologyof the present application.

FIG. 27B provides a cross-sectional view of the oversized rotary drilledhole of FIG. 27A with a rotated and retracted Dynamic Lateral Pad (DLP).

FIG. 28 provides a cross-sectional view of an oversized rotary drilledhole at the location of a cross-section of a deployed Dynamic LateralPad (DLP) experiencing a deviation bias.

FIG. 29 provides a generalized top view of a borehole centerline over abrief drilling interval under the influence of a deviation force,restoration force provided by a Dynamic Lateral Pad (DLP), and resultantpenetration force consistent with the technology of the presentapplication.

DETAILED DESCRIPTION

The technology of the present application will now be described morefully below with reference to the accompanying figures, which form apart hereof and show, by way of illustration, specific exemplaryembodiments. These embodiments are disclosed in sufficient detail toenable those skilled in the art to practice the technology of thepresent application. However, embodiments may be implemented in manydifferent forms and should not be construed as being limited to theembodiments set forth herein. The following detailed description is,therefore, not to be taken in a limiting sense. Moreover, reference maybe made to the figures using relatively locational or directional terms,such as, for example, top, bottom, left, right, axial up, axial down,radial outward, radial inward, or the like. The terms are used todescribe relative movement and locations and should not be consideredlimiting.

The technology of the present application is described, in someembodiments, with specific reference to steerable motor systems.However, the technology described herein may be used for otherapplications including, for example, vertical drilling as well asdirectional drilling, and the like. Additionally, certain embodiments ofthe technology of the present application may be generally describedwith respect to a dual rotating cutting system having inner and outerbits or cutting structures that may include motor systems incorporatinga bent housing that is not used for active directional drilling changerequiring slide drilling. One of ordinary skill in the art will nowrecognize, on reading the disclosure, that more than two cuttingstructures are possible by providing inner, intermediate, and outercutting structures for example. Moreover, the technology of the presentapplication will be described with relation to exemplary embodiments.The word “exemplary” is used herein to mean “serving as an example,instance, or illustration.” Any embodiment described herein as“exemplary” is not necessarily to be construed as preferred oradvantageous over other embodiments. Additionally, unless specificallyidentified otherwise, all embodiments described herein should beconsidered exemplary.

FIG. 2 shows a cross-sectional view of Dynamic Lateral Pad (DLP) system200 consistent with the technology of the present application. DLPsystem 200 is shown in isolation from the remainder of the drill stringfor convenience. DLP system 200 includes a unitary, integral, ormonolithic drill bit/drive shaft 202 (hereinafter integral or monolithicdrill bit/drive shaft). Integral drill bit/drive shaft 202 has distalend 203 that terminates in a plurality of cutters 204. Cutters 204, inthis case, are shown as PDC cutters, but could be, for example rollercones or the like. Integral drill bit/drive shaft 202 has a firstdiameter (generally the diameter of bit gauge 210) at the distal end ofD′. Integral drill bit/drive shaft 202 also has proximal end 206 coupledto the transmission which then is connected to the rotor of the powersection (shown below with reference to FIGS. 3A and 3B). Integral drillbit/drive shaft 202 has a second diameter at the proximal end of D″. Asshown, D′ is generally greater than D″ such that the drill bit portionof integral drill bit/drive shaft 202 extends the diameter of, but alsorotates within, the wellbore (not shown); whereas, the drive shaftportion of integral drill bit/drive shaft 202 fits and rotates withindrill string housing 208, therefore drill string housing 208 mustgenerally have a diameter that is equal to or less than D′.

Distal end 203 of integral drill bit/drive shaft 202 has an axialsurface formed by bit gauge 210 and upper radial surface 212. Pad hole214 extends through bit gauge 210 radially inward a distance d₁ andforms a volume. Actuator hole 216 extends from upper radial surfaceaxially downward a distance d₂ and forms a volume that intersects withpad hole 214. Pad 218 is sized to movably engage pad hole 214. Pad 218moves radially in and out as shown by arrow B. Pad 218 may include astop 219 to inhibit pad 218 from exiting pad hole 214. Acceptable pad218 materials include hardened steel or ceramic that would be known tothose ordinarily skilled in the art. Actuator 220, which is shown as apush rod, or cam follower is sized to movably engage actuator hole 216.By way of reference, the term actuator should be construed as a device,structure, or means to provide a motive force tending to cause theassociated pad (or pads) to move radially in at least one direction.Actuator 220, which is one exemplary means for actuating, rides betweenpad 218 and the axial cam profile formed in the distal end ofnon-rotating axial cam sleeve 224. Axial cam sleeve 224 terminates in aspiral shaped or ramped cam surface 225. The spiral shape or ramp of camsurface 225 means cam sleeve 224 extends further on one side of integraldrill bit/drive shaft 202 than the other and that cam surface 225 has acontinuous, potentially constant slope up and down between minimum andmaximum axial extension. Actuator 220 moves laterally up and down asshown by arrow C. Axial cam sleeve retainer 222 and axial cam sleeve 224are operatively coupled and connected to the housing of the drillstring. As the integral drill bit/drive shaft rotates relative togenerally non-rotating housing 208, sleeve retainer 222 and axial camsleeve 224. Axial cam sleeve 224 acts on actuator 220 to cause theactuator to slide, in this exemplary embodiment, into actuator hole 216.Sloped surface 226 of actuator 220, in this exemplary embodiment, drivespad 218 radially out to an extended position. Reactive force from thewellbore wall (not shown) on pad 218 acts to move pad 218 to a flushposition as the axial cam rotates back to the start position. A bearingassembly 228, as is conventional, supports integral drill bit/driveshaft 202 in housing 208.

For convenience and understanding, in certain aspects, reference will bemade to the parts and components of a drill string described in FIG. 1while describing the technology of the present application. Powersection 20 to which an integral drill bit/drive shaft 202 is connectedcomprises a transmission, mud turbine, positive displacement mud motoror other type of apparatus that creates suitable drilling actiondownhole. Other such apparatus include an electric motor, reciprocatingmotor or other type of motor to facilitate driving integral drillbit/drive shaft 202 or, as is conventional today, drill bit 14 connectedto bit box 34 that is part of drive shaft 46. As one of ordinary skillin the art would understand, a drill string having for example apositive displacement motor includes: (1) a power section, whichcomprises the rotor and stator, (2) drive shaft, optionally (3) a benthousing (generally only included in directional assemblies), (4) atransmission coupling the power section to the drive shaft, and (5) abit box to connect a conventional bit. Referencing back to FIG. 1,conventional drive shaft 46 is contained in a bearing housing 24 havingboth axial and radial bearings 44. The distal end of drive shaft 46typically terminates in bit box 34 containing an API connection 37 (notshown) appropriate for the hole size being drilled. A separate drill bit14, having a corresponding thread, is coupled to the distal end of driveshaft 46 through API connection 37 (not shown) on bit box 34.Connections other than threaded connections are possible such as a weld,interference fit, or other non-threaded attachment.

Although introduced as part of DLP system 200, integral drill bit/driveshaft 202 would increase the effectiveness of most drilling systems,including conventional steerable motor system 10, rotary steerablesystems (not shown) and straight hole motor systems 300 (FIG. 3A),without incorporating dynamic lateral pad system 200 described in FIG.2. As compared to conventional designs, providing monolithic or integraldrill bit/drive shaft 202, as shown above, allows reduction of thedistance from the most distal bearing set and the distal end of anydrilling assembly. In directional assemblies with bend 35, integraldrill bit/drive shaft 202 also allows reduction of the distance frombend 35 to distal end 52 of drill bit 14. Decreasing the distance fromthe most distal bearing set to the distal end of the drilling assemblyand decreasing the distance from the bend on directional assemblies tothe distal end of the bit improves drilling performance. By example, theshortened distance from the distal end of the bit to the bend on anydirectional assembly, generally means a more aggressive ability to movethe drill axis off vertical or to change wellbore direction. Theshortened distance from the most distal bearing set to the distal end ofthe drilling assembly significantly reduces counter-productive flex andpossible failure points related to the added length required to form andservice the connections. The shortened distance also reduces bendingmoments in the drive shaft resultant from the flex created by theconnection of bit box 34 and drill bit 14. Decreased bending momentsreduce bearing loads and resultant wear in all motors and other systemsdescribed above and reduce the potential for erratic bending vectorsattributed to misalignment of the conventional API bit box and drill bitconnection. Cutters of integral drill bit/drive shaft 202 could be madewith any rock destroying cutting structures (i.e.; PDC, Roller Cone,Impregnated, Natural Diamond, etc.)

FIG. 3A shows a side by side comparison of a conventional motor drillstring 300 and improved motor drill string 390 using integral drillbit/drive shaft 202 of the present application described above (bothdrill strings are without a bend). Both drill string 300 and drillstring 390 include power section 320, transmission section 322 andbearing section 324. Conventional motor drill string 300, however,incorporates conventional drive shaft 346 with bit box 334, and separatedrill bit 314 having API connection 337 (not shown) to couple to bit box334. Conversely, improved motor drill sting 390 has a monolithic orintegral drill bit/drive shaft 202. By replacing conventional driveshaft 346 and drill bit 314 with integral drill bit/drive shaft 202,distal end 352 of conventional motor drill string 300 is a distance Lfarther from bearing section 324 than distal end 352′ of improved motordrill string 390.

FIG. 3B shows a side by side comparison of conventional directionaldrill string 391 and improved directional drill string 392 usingintegral drill bit/drive shaft 202 of the present application describedabove (both drill strings include a bend). Similar to the above, bothconventional drill string 391 and improved drill string 392 includespower section 320, transmission section 322 and bearing section 324. Inthis example, conventional drill string 391 and improved drill string392 also includes bent housing 335. Conventional directional drillstring 391, however, incorporates a conventional drive shaft 346 withbit box 334, and separate drill bit 314 having API connection 337 (notshown) to couple to bit box 334. Conversely, improved directional drillstring 392 has a monolithic or integral drill bit/drive shaft 202. Assuch, distal end 352 of conventional directional drill string 391 is adistance L′ farther from the bend in bent housing 335 than distal end352′ of improved directional drill string 392.

Conventional directional drill string 391 has longitudinal axis Aextending above and through power section 320 and, after the bend,longitudinal axis B extending through drive shaft 334 and drill bit 314of drill string 391. Improved directional drill string 392 haslongitudinal axis C extending above and through power section 320 and,after the bend, longitudinal axis D extending through integral drill bitand drive shaft 202 of improved drill string 392. Axis A and axis B formangle α and axis C and axis D form angle β, where angle β is capable ofbeing less than angle α yet have the same or greater build ratesprovided the ratio of angle α to angle β is equal to or less than theratio of the bit to bend distance (BTB) of conventional directionaldrilling string 391 and the bit to bend distance (BTB) of improveddirectional drill string 392. Build rate is generally computed as theangular change of the wellbore path over a set distance, such as 100feet or 30 meters. As shown, the cutters are conventional PDC cutters,but most any cutting structures and/or cutting elements are usable.Similar to FIG. 3A, FIG. 3B provides drill string 391 with conventionaldrill bit 34 and drill string 392 with integral drill bit and driveshaft 202 without DLP system 200 or DLC system 800 or combination,although DLP system 200 or DLC system 800 or combination could be usedwith any of the configurations shown in FIGS. 3A and 3B.

As can now be appreciated, shorter lengths and smaller bends providebenefits for the overall drill operation. In certain aspects, theconfiguration of improved drill strings 390 and 392 provide reduction instress on critical components most notably the drive shaft and bearingassemblies, reduction in magnitude of cyclical loads, higher build ratesat lower bend angles, reduction in drag (resistance to axial movementalong the path of the wellbore), increased power, and reduced bendingmoments as compared to conventional drill strings 300 and 391.Eliminating the connection also allows for the potential for moreefficient and effective use of downhole sensors, power sources forsensors, potential communication devices and additional actuators. Thesesensors, devices, actuators and power sources can now be placed incloser proximity to the cutting structure area or in other longitudinalspace made available because of the shorter length of integral bit/driveshaft 202. In addition, support wires and tubing can be prearrangedduring assembly at the shop, eliminating the hindrance of managingsupport wires and tubing across a rotary connection on the rig floor.

With reference back to FIG. 2, integral drill bit/drive shaft 202comprises drill bit portion 401 with drive shaft portion 403 with nofield connectors between the two portions. Drill bit portion 401 anddrive shaft portion 403 are generally formed as a single unit, such asfor example, machined from a single high strength steel forging,machined from a high strength metal bar, as an assembly between a lowcarbon steel bit core with drill bit matrix or steel bit head welded,shrink fit or chemically bonded to a drive shaft made from high strengthsteel. Alternatively, a custom or API threaded connection with noprovision (axial length) included to make or break the connection at thedrilling location.

FIG. 4A provides a side view of DLP drill string 400 in wellbore 452drilled in formation 450. Drill string 400 includes power section 406,bent section 408 (and an associated scribe line (not specificallyshown)), bearing housing 410 and DLP system 200 (first presented in FIG.2). As shown, DLP system 200 includes a cam sleeve retainer 222, camsleeve 224 and drill bit portion 401 with a number of blades 412 eachincluding actuator 220, pad 218, and cutters or attached integralcutting structures 414, such as the PDC cutters shown. While shown asconventional blades 412 and cutting structures 414, the use of the DLPsystem 200, and other DLP system or the dynamic lateral cutter (DLC)system described below, may allow for customization of the blades 412and cutting structures 414 to take advantage of the unique movement ofthe drill bit portion 401 caused by the DLP systems and DLC systemsdescribed herein.

FIG. 4B provides a cross-sectional view of DLP drill string 400 shown inFIG. 4A and illustrates the directional drilling action of drill string490 in operation. In particular, because actuator 220 ₁ has movedaxially downward due to the rotation of drill bit portion 401 relativeto stationary axial cam sleeve 224 and ramped cam surface 225, pad 218 ₁extends radially outward from blade 412 ₁ pressing against wellbore 452.Pad 218 ₁ provides force A pressing against wellbore 452. Force Aresults in pushing bit portion 401 in a direction opposite as shown byarrow B increasing the side cutting force of bit portion 401 againstwellbore 452. As can be appreciated; pad 218 ₁, currently shown asextended radially in FIG. 4B, rotates 360° with bit 401 aboutlongitudinal axis E. Pad 218 ₁ is extending the most directly oppositethe direction an operator desires to steer the bit, which is the targetdirection, which target direction is typically associated with thescribe line as described above. Ideally, pad or pads 218 (including pad218 ₁) are completely retracted and either inset or flush with theblade's axial wall or bit gauge 210 when the pad is oriented in thetarget direction, which is generally when aligned with the scribe lineas described above. Depending on operating conditions, desired build,and formations associated with the wellbore, the pad 218 ₁ may not bedirectly opposite the target direction and scribe line but rather havethe maximum extension offset less or more than 180° from the scribeline.

While not limiting, the direction in which the operator desires to steerthe bit, or target direction, will be designated as 0° with drill string490 stationary and oriented such that ramped cam surface 225 of axialcam sleeve 224 provides maximum extension of pad 218 ₁ at 180°, althoughas described above, operating conditions, desired build, and formationsmay alter the general case. As appreciated, the 0° target direction alsomay be aligned with the scribe line in certain embodiments. In otherembodiments, the target direction of the bit may not be associated witha scribe line. As blade 412 ₁ rotates around longitudinal axis E, axialcam sleeve 224 moves actuator 220 ₁ down forcing outward movement of pad218 ₁ from flush or inset to extended. Similarly, from 180° to 360°, therelative rotation of axial cam sleeve 224 allows actuator 220 ₁ to moveup thus allowing pad 218 ₁ to move inward from maximum extension back toflush or inset. While described over a full rotation, pad 218 ₁ mayextend only at 180° in certain embodiments. In other embodiments, pad218 ₁ may be flush from 0° to 45° and from 315° to 360° (the pad isextended from 45° to 315°). In still other embodiments, pad 218 ₁ may beflush from 0° to 90° and from 270° to 360° (the pad extended from 90° to270°). The range of motion for pad 218 ₁ is provided by axial cam sleeve224 having a ramped cam surface 225. While described as symmetricalranges, the ranges may be asymmetrical and rotationally offset as well.In addition, an oscillating cam profile can be provided such that thepad or pads may extend and retract partially or fully and may extend andretract multiple times during each rotation to add constant side forceor pulsating side force or both in addition to the conventional forcespushing the cutters.

In addition to force A pushing to increase the side cutting force of bitportion 401 as shown by arrow B, force A literally moves bit portion401, including a portion of drill string 400 laterally. This movement,coupled with the vibration created by repetitive extension andretraction of actuators 220 and pads 218 can potentially reduce frictionbetween drill string 400, including the steerable motor (not shown), andwellbore 452 by breaking the static friction that normally occurs withnon-rotating steerable motor system 10 (FIG. 1). Additionally, lateralmovement of drill bit portion 401 and drill string 400 can potentiallybreak a seal that can form between drill string 400 and formation 450caused by differential sticking from over pressure of the drillingfluids in a permeable formation 450.

FIG. 4C provides a cross-sectional view of DLP drill string 491 to helpillustrate a unique and highly beneficial supplemental bit motionprovided by all the dynamic lateral pad system. Drill string 491 isidentical to drill string 400 and drill string 490 (FIGS. 4A and 4Brespectively) except drill string 491 (FIG. 4C) does not include bend408 shown in FIGS. 4A and 4B. As previously described, because actuator2201 moves axially downward due to the rotation of drill bit portion 401relative to stationary axial cam sleeve 224 and ramped cam surface 225,pad 218 ₁ extends radially outward from blade 412 ₁ pressing againstwellbore 452. Pad 218 ₁ provides force A pressing against wellbore 452and pushing bit portion 401 in a direction opposite as shown by arrow B.This increases the side cutting force of bit portion 401 acting againstthe sidewall of wellbore 452 while simultaneously moving the center ofthe bit laterally, as shown by arrow C, providing lateral cutting actionat the center of wellbore 452. This lateral cutting action at the centerof wellbore 452 reduces conventional drill bit inefficiencies byreducing or eliminating the possibility for pure drill bit portion 401rotation that only fails rock by compressive failure. Moving the drillbit off its longitudinal axis provides a number of benefits over aconventional drill. One benefit is that conventional drill bits providedlimited cutting forces at the geometric center of the drill bit, whichis in part due to the lower rotational velocity of the cuttingstructures near the geometric center of the bit. The DLP system pushesthe drill bit off the longitudinal axis and moves the geometric centerof the drill bit as the drill operates. This also allows cuttingstructures with a higher rotational velocity (rpm) to drill the pile offormation that can build up at the center of the bit. While mostbeneficial with drilling systems without a bend like drill string 491,drill string 300, drill string 390 (FIG. 3A) and DRCS system 1000(described below), drilling systems with a bend, like drill string 400,drill string 391, drill string 392 (FIG. 3B) and conventional drillstring 12 (FIG. 1), also benefit.

As described above, pad 218 may be provided on a drill string with anintegral drill bit/drive shaft or on a conventional steerable motorstring having a drill bit coupled to a drive shaft with bit boxdescribed above. FIG. 5A provides a cross-sectional view of a dynamiclateral pad (DPL) system 500 having a drive shaft 502 with bit box 504at distal end 503 of drive shaft 502. Drill bit 506 with API connection508 is coupled to bit box 504. Similar to drill bit portion 401described above, drill bit 506 has a plurality of blades 510. Blades 510have an axial outer wall 512 with pad hole 514 to receive pad 516.Blades 510 form channel 518 with bit box 504 into which radial camsleeve 520 is operationally fitted. Drill bit 506, blades 510, outerwall 512, pads 514 and drive shaft 502 rotate together relative to thegenerally non-rotating cam sleeve 520, cam sleeve retainer 524 and drillstring housing 522. Cam sleeve 520, in a manner similar to actuator 220described above, moves pad 516 from a flush to an extended position,which pad 516 is currently shown extended. Cam sleeve 520 is coupled todrill string housing 522 by cam sleeve retainer 524. As previouslypresented, pad 516, presses against formation 550 providing a forceshown by arrow A. Force A pushes the bit in a direction opposite asshown by arrow B. Also as previously presented, the cam action canprovide symmetric, asymmetric or mixed motion.

FIG. 5B provides multiple end views of DLP string 500 in FIG. 5A showingthe relative position of pad 516 in a progression of incremental 90degree rotational steps by drill bit 506. While not limiting, the targetdirection in which the operator desires to steer the bit is shown by adouble arrow T and will be designated as 0°. View 560 presents pad 516positioned directly opposite target direction T at 180 degrees relativerotation, at maximum extension and pushing bit 506 in target directionT. As mentioned above, this exemplary embodiment describes the generalcase where the pad is extended a maximum distance directly opposite thetarget direction T. In certain embodiments, the maximum extension of thepad may be offset from 180 degrees. Also, for embodiments where thedrill string has a bend or scribe line (as described above), the targetdirection T is generally aligned with the scribe line. As bit 506rotates in direction R by 90 degrees into view 570, as shown by arrowR₉₀, rotationally stationary axial cam 520 allows extension of pad 516to decrease as shown by arrow B. As bit 506 rotates an additional 90degrees into view 580, for a total of 180 degrees displacement as shownby arrow R₁₈₀, pad 516 is oriented in target direction T but is notvisible, as pad 516 has moved to the flush or inset position. Rotationinto view 590, as shown by arrow R₂₇₀, extends pad 516 as shown by arrowC. Continued rotation to 360 degrees brings pad 516 back to the fullyextended position shown by arrow A in view 560.

FIG. 6 shows DLP system 600 with multiple pads 608 having radial camsleeve 602 that is operatively coupled and connected to the housing ofdrill string 610. Integral drill bit/drive shaft 604 rotates relative tothe generally non-rotating (during steering of the bit) cam sleeve 602.Radial cam sleeve 602 fits around integral drill bit/drive shaft 604,above bit portion 601 to acts on pads 608. Radial cam sleeve 602 hascontinuous circumferential cam race 603 with variable radial width asshown by the cross-sectional view in FIG. 6. Pad 608 ₁ is shown in anextended position while pad 608 ₂ is shown to be approximately flush.Radial width Wi of cam race 603 on axial cam sleeve 602 is greater atpad 608 ₁ than the radial width W₂ of radial cam sleeve 602 at pad 608₂. The variable radial width of cam sleeve 602 may range from a minimumto a maximum. The minimum radial width would generally be located at thepoint closest to the direction in which the drill bit is to be pointed,whether a bent or straight drill string configuration; whereas, themaximum radial width would generally be located at a point opposite. Asis well known by those familiar in the art, cam race 603 could be formedsimply as an off center circle or profiled to better optimize pad 608movement. Examples of potentially optimized pad 608 movement includesteeper slopes for cam race 603 to provide more aggressive or fastermovement of pad 608, non-symmetric pad movement and a plurality of fullor partial pad 608 movements, in and out, per rotation.

FIG. 7 shows DLP system 700 with shank cam. As can be appreciated, DLPsystem 700 with shank cam includes integral drill bit/drive shaft 706having drill bit portion 701, shank cam portion 702 and drive shaftportion 704. Shank cam portion 702 includes radial cam race 703 thatencircles or partially encircles integral drill bit/drive shaft 706.Radial cam race 703 has variable radial width about the perimeter ofintegral drill bit/drive shaft 706 from a minimum radial width W₄ to amaximum radial width W₃. At maximum radial width W₃, pad 710 is extendedto push against wellbore wall 752 a maximum amount to provide additionalside force to actively steer the bit in the desired direction. Atminimum radial width W₄, pad 710 is retracted by contact with well bore752 to become flush or even slightly inset relative to the outerdiameter of pad carrier 715 thus discontinuing the added side force tothe drill bit. Pad 710 is physically positioned in slot 714 formed inpad carrier 715 and is operationally coupled to pad carrier 715 andshank cam portion 702 of integral drill bit/drive shaft 706. Pad carrier715 allows radial movement of pad 710 and the combination of shank camportion 702 and well bore 752 provides the radial locomotion. Integraldrill bit/drive shaft 706 with shank cam portion 702 rotates relative tothe generally non-rotating (during steering of the bit) pad 710 and padcarrier 715 that is fixedly connected to housing 716 and the drillstring above (not shown) by retainer 716. Integral drill bit/drive shaft706 is rotatably coupled to string housing 712 with bearing assembly 718as is generally known in the art. As one of ordinary skill in the artwould appreciate on reading the application, DLP system 700 could beimplemented with a conventional bit coupled to a conventional driveshaft as described throughout the application.

An alternate embodiment to retain and retract pad 710 would provide fora “T” shaped or similar slot (not shown) fabricated into shank camportion 702 with a complementary “T” shaped profile (also not shown)attached to pad 710. This would allow the cam to both push with cam raceportion 703 to extend pad 710 and pull to retract pad 710 with the “T”slot. Additionally, a spring or springs (not shown) could be introducedbetween pad 710 and cam race portion 703 or pad 710 and pad carrier 715to maintain continuous contact between pad 710 and wellbore 752.Conversely, a spring or springs (not shown) could be introduced betweenpad 710 and cam race portion 703 or pad 710 and pad carrier 715 toretract pad 710 away from wellbore 752 when cam race portion 703 isapproaching a minimum position.

As described generally above, the DLP systems provide for a pad that isradially movable inward and outward with respect to the centrallongitudinal axis of the drill string housing. The DLP pad pushesagainst the wellbore to move the drill bit (or drill bit portion of thedrill string) in an opposing direction that would generally be thedesired direction to accomplish the drilling objectives whether adirectional drill or a straight drill. In certain aspects, the DLP maypush against the wellbore to position the drill bit to help mitigateharmful rotational patterns or vibration tendencies also supportingdrilling efficiency gains. Combining the DLP systems with a bent housingand integral drill bit/drive shaft would further optimize this technicalgain.

FIG. 8A shows a partial section view of DLC system 800 providing aplurality of Dynamic Lateral Pads (DLPs) and a plurality of DynamicLateral Cutters (DLCs). The basic DLC system 800 includes dynamiclateral pad with a cutter or series of cutters in certain aspects. Aswith the above, DLC system 800 is shown with integral drill bit/driveshaft 802 to reduce the overall distance between distal end 804 of drillstring 806 and bend element 818. Integral drill bit/drive shaft 802 isrotatably coupled to drill string 806 by bearing assembly 832. Whileshown as with an integral drill bit/drive shaft 802 with drill bitportion 808 and drive shaft portion 810, DLC system 800 could also use aconventional drill bit and conventional drive shaft as described herein.DLC system 800 further comprises pad 812 having a cutting element orcutting assembly 814. Pad 812 is generally referred to as cutting pad812 to distinguish from other pads as will be clear below. Cutting pad812 is attached, in this exemplary embodiment, to a removable padcarrier and guide or cage 816. Removable cage 816 is similar to theblades described above, but rather than being machined into the drillbit portion of integral drill bit/drive shaft 802, cage 816 may beremoved and replaced with a compatible alternate cage (not shown)allowing for greater operational flexibility and control regarding thelocation and number of pads that are radially positioned. Cage 816 maysnap fit into a slot on integral drill bit/drive shaft 802 or, in otherembodiments, cage 816 may be bolted, threaded, pinned, welded,chemically bonded or otherwise connected to integral drill bit/driveshaft 802.

Similar to embodiments described above, cutting pad 812 moves inward andoutwardly based on an actuator, which, in this exemplary embodiment, iscam sleeve 820 having cutting pad cam race 822. Cam sleeve 820 iscoupled to drill string 806 using retainer 824. Cutting pad cam race 822may have a variable radial width similar to the widths described above,but not re-summarized here. The wellbore sidewall 852 would be subjectto more cutting force the further outward cutting pad 812 extends andwith greater numbers of cutter pads 812. DLC system 800's destruction offormation 850 and therefore movement of bit portion 808 would be in thedirection of cutter pad 812 extension.

Further, DLC system 800 may have bearing pad or pads 826. The bearingpad is similar to the non-cutting pads described above and is referredto as a bearing pad as it does not including a cutting element. In thisexemplary embodiment, the position of bearing pad 826 is controlled by asecond actuator, bearing pad cam race 830, which is also part of camsleeve 820. Bearing pad cam race 830 has a variable radial thicknessgenerally 180 degrees out of phase with cutting pad cam race 822 suchthat bearing pad 826 pushes against the side of wellbore 850 a maximumamount when the opposite cutting pad 812 is exerting the maximum cuttingforce. As shown, cutting pad cam race 822 and bearing pad cam race 830are provided on sleeve 820, but could alternatively be provided inseparate sleeves, machined directly into drive shaft portion 810, or acombination thereof. Similarly, both pads could use an actuator similarto actuator 220 described with respect to FIG. 2 above. Based upon theabove teaching, one ordinarily skilled in the art could easily see thatmany additional cam races driving many additional bearing pads andcutter pads, with similar or differing cutting structures, operationallyin or out of phase or operationally independent of the other actuatorscould be implemented.

FIG. 8B shows an elevation view of an exemplary DLC system 800 with anodd number of blades 828 and removable cage (not visible) with cuttingpad 812 and bearing pad 826 axially aligned with each blade 828. Theexemplary elevation view shows a cutting pad 812 ₁, and bearing pads 826₃ and 826 ₄ in extended positions providing a direct, balanced andgenerally stable resultant force from the combination of force A₃ andforce A₄. The resultant of force A₃ and force A₄ moves drill bit, andtherefore the wellbore to be drilled, in the desired direction byproviding added side force to drill bit portion 808 plus cutting forceB₁ from cutting pad 812 ₁ with cutter 814 ₁ to independently scrape orcrush the wellbore sidewall (not specifically shown). Based upon theabove teaching, one ordinarily skilled in the art could easily see thatthis could also extend to DLC systems with a plurality of asymmetricallymounted bearing and cutting pads and to DLC systems with an odd or evennumber of blades with or without a plurality of cutting pads and/orbearing pads.

In the exemplary embodiment of a five (5) bladed DLC system 800described by the combination of FIGS. 8A and 8B, first cam race 822 isprovided to drive cutter pads 812 and second cam race 830 is provided todrive bearing pads 826. In this embodiment and with appropriate profilesfor cutting pad cam race 822 and bearing pad cam race 830, as integraldrill bit/drive shaft 802 rotates relative to cam sleeve 820, bearingpad cam race 830 approaches and extends bearing pad 826 ₃ in advance ofbearing pad 826 ₄ potentially introducing additional rock cuttingactions. With cutting pad 812 ₁ also extended, the earlier extension ofbearing pad 826 ₃ will cause bit portion 808 and cutter pad 812 ₁ topotentially tip and change the angle of attack of cutter 813 ₁. As bitportion 808 continues rotation, bearing pad cam race 830 rotates under,and extends bearing pad 826 ₄ to bring the angle of attack of cutter 814₁ back to neutral. Similarly, with continued rotation, bearing pad 826 ₃retracts before bearing pad 826 ₄ causing bit portion 808 and cutter pad812 ₁ to potentially tip and change the angle of attack of cutter 814 ₁in the reverse direction. Depending on the specific profiles of cuttingpad cam race 822 and bearing pad cam race 830 similar tipping actioncould be created by the cutting pads.

Referencing FIG. 8B, simultaneous extension of bearing pad 826 ₃ andbearing pad 826 ₄, or any pair of pads, can be provided by introducing asecond bearing pad cam race with identical profiles but out of phase, by⅕ of a revolution (for a 5 bladed system). This would cause both bearingpads to extend and retract in unison. Based upon the above teaching, oneordinarily skilled in the art could easily see the possibility ofadditional cam races, additional cutter pads and additional bearingpads, limited only by the space, particularly length required to fit thecomponents. In addition, one ordinarily skilled in the art could easilysee that pad profiles can be manipulated to extend, retract, hold andoscillate in an almost limitless number of permutations and combinationswhile controlling both the amount of lift and timing. Further, the padscould also contain sensors that extend and retract.

Rocker arms (not shown) provide another alternative actuator allowingmultiple actuators to operate simultaneously off a single reference,like a cam. In addition, a rocker arm actuator, hinged between an inputof force and the output, reverses the direction of motion like ateeter-totter; a rocker arm actuator can be used to operate both acutter pad and bearing pad from a single cam race. In anotherembodiment, a single cam could be used to drive a hydraulic pump, theoutput of which could be ported to any number of hydraulic actuators.

DLC system 800 (FIG. 8A) provides moveable lateral cutting structuresopposite one or more moveable lateral pads providing enhanced cuttingaggressiveness, primarily with side cutting action, to support thedirectional change capability in directional wells and in vertical wellswhere the objective is to stay close to vertical. DLC system 800 invertical wells, associated or not with an optimized fixed cuttingdesign, would be used to nudge the wellbore back to vertical when thewellbore has drifted off the planned vertical axis. As extension of thepad is controllable based on orientation, location, width of theactuator, profile of the cam race or the like acting on the pad, theextension of a pad can be used to enhance or negate/offsetaggressiveness of angular deviation of a drill bit while initiallydrilling a wellbore or correct unwanted deviations for after the initialdrilling of a wellbore section. In certain aspects, as described above,the pad may include a cutting element and, as a pad pushes against thewellbore, a cutter or series of cutters in an opposing pad or cutterassembly may destroy rock in the opposing section of the wellbore.

Previously, all pad hole extension paths for DLP systems (200, 400, 500)and DLP/DLC system 800 were oriented perpendicular to the axis ofrotation and all pad faces were oriented parallel to the axis ofrotation. In certain applications, changes to the pad hole extensionaxis and changes to pad face orientation can improve system overallperformance. Using DLP system 500 as exemplary, FIG. 9 shows enlargedviews of a base pad mechanism 900, consistent with pad hole extensionpath Pi perpendicular to axis of rotation A and pad face 518 ₁orientation parallel to axis of rotation A as presented in each of theexemplary embodiments presented above. Also shown in FIG. 9 is a secondexemplary pad mechanism 920 that adds to base pad mechanism 920, padface 518 ₂ that is closer to parallel with well bore 552. FIG. 9 alsoincludes a third exemplary pad mechanism 940 that reorients hole padextension axis P₃ to provide pad face 518 ₃ that is closer to parallelwith well bore 552. A fourth exemplary pad mechanism 960 significantlyreorients hole pad extension axis P₄ while providing pad face 518 ₄close to parallel with well bore 552 with possible modifications tobetter grip well bore 552 described later.

Referring to FIG. 9, base pad mechanism 900 includes pad 516 ₁ that isconstrained by pad hole 514 ₁ to limit motion to the radial direction.Pad hole 514 ₁ is contained in axial outer wall 512, part of drill bit506. Pad 516 ₁ translates along pad hole axis P₁ that extends radially,perpendicular to axis of rotation A of drill bit 506. Pad 516 ₁ extendsand retracts as cam sleeve 520 rotates under pad cam face 519 ₁ that isparallel to the curvature of pad well bore face 518 ₁. As previouslydiscussed, when DLP system 500 includes a bend (not shown), axis ofrotation A of drill bit 506 is offset from the drill string axis andtherefore well bore 552 by a magnitude close to the magnitude of thebend angle. When loaded during the directional drilling process, thetilt of drill bit rotation axis A typically increases and may more thandouble the unloaded tilt depending on such things as the well boregeometry, load applied and the geometry of the associated drillingequipment. Assuming the tilt of rotation axis A is doubled relative tothe bend angle, results in a misalignment angle ϕ₁ between pad well boreface 518 ₁ and well bore 552 that is twice the bend angle. Misalignmentbetween pad well bore face 518 ₁ and well bore 552 can add wear to pad516 ₁ and cause rock destruction at the contact point, directly oppositethe target direction. The item numbers included but not cited areprovided as reference to tie back to DLP system 500 (FIG. 5A).

Again referencing FIG. 9, second pad mechanism 920 is virtuallyidentical to base pad mechanism 900 with the exception that pad wellbore face 518 ₂ of pad 516 ₂ is profiled to be more generally parallelto well bore 552 under load. Using the previous example of a bend in theassembly and the assumption that, under load, the tilt of rotation axisA is doubled relative to the bend angle; leads to profiling the angle ofpad well bore face 518 ₂ by twice the angle of the bend.

Continuing to reference FIG. 9, third pad mechanism 940 creates pad wellbore face 518 ₃ of pad 516 ₃ that is generally parallel to well bore 552by rotating pad hole axis P₃ from perpendicular as shown by angle θ₃.Assuming again a bend in the assembly and, when under load, the tilt ofrotation axis A is doubled relative to the bend angle; leads to rotatingpad hole axis P₃ from perpendicular by twice the angle of the bend.While addressing possible wear to pad 516 ₃ and unintended rockdestruction directly opposite of the target direction, this mechanismreduces force delivered to pad 516 ₃ by the sine of the angle of padhole axis P₃ rotation unless the profile of the cam pad face 519 ₃ is atleast partially conical to be parallel to pad well bore face 518 ₃ andthe cam sleeve 520 profile matches the profile of cam pad face 519 ₃.

Fourth pad mechanism 960 contains all the parts of the three precedingmechanisms but adds a new dimension to pad action. By further rotatingpad hole axis P₄ from perpendicular as shown by angle θ₄, that isgreater than the tilt of rotation axis A under load, pad 516 ₄ can beused to simultaneously push the bit sideways and momentarily push drillbit 506 along the axis of rotation A. To achieve optimal results in someapplications, for example in hard competent formations, improvementscould be provided in the pad well bore face 518 ₄ to reduce pad 516 ₄slippage relative to formation 550. There are many ways to decrease theprobability that pad 516 ₄ will slip relative to formation 550 includingadding a rubber pad to pad well bore face 518 ₄, under or over rotatingpad hole axis P₄ in relation to pad well bore face 518 ₄ to promote ageometry that tends to gouge formation 550 (the reverse objective ofsecond pad mechanism 920 and third pad mechanism 940) and introducinghardened steel, carbide, PDC or like teeth to pad well bore face 518 ₄.Although, all pads might visually appear as “not sealed” and as havingsharp edges, this should not be considered to be in any way limiting.Each alternative such as sealing, or not, and edge details such assharp, tapered, chamfered, well rounded and half dome bring potentialadvantages and disadvantages to be considered relative to the specificimplementations and drilling objectives.

FIG. 13 provides a section view of drill string 1300 with DynamicLateral Pad (DLP) inclusive of conventional bit 14 at distal end 1352.In this exemplary embodiment, drill string 1300 includes the componentsdescribed by drill string 12 (FIG. 1) as positioned above bearingpackage 24 with the possible exception of bend 35 that may or may not beincluded depending on the desired aggressiveness of the drillingobjectives. Returning to FIG. 13, drill string 1300 also includesbearing housing 1322 connected to the distal end of transmission housing36 (FIG. 1) and drive shaft 1302 inclusive of bit box 1304 and cam race1303 connected to the distal end of transmission drive line 38 (FIG. 1).Drill bit 14 is connected to bit box portion 1304 of drive shaft 1302 byAPI connection 37. Drill string 1300 further includes pad carrier 1320with raised section 1326, slot 1321, mounting provisions 1329 for padhinge pin 1318, and torsion lock pin 1323 to engage axial slot 1325 cutinto bearing housing 1322 to prevent rotation of pad carrier 1320relative to bearing housing 1322. Pad carrier 1320 is fixedly mounted tobearing housing 1322 with retainer 1324 and torsion lock pin 1323. Padassembly 1314 is comprised of pad 1316, cam follower 1315 and elasticelement 1327. Pad 1316 includes hinge portion 1317, and mountingprovisions 1328 to operationally attach hinge pin 1318. Pad assembly1314 is operationally positioned in slot 1321 with a hinged connectionto pad carrier 1320 and contacting cam race 1303 with cam follower 1315of pad assembly 1316.

While similar to DLP system 700 (FIG. 7), drill string 1300 with DynamicLateral Pad (FIG. 13) incorporates conventional drill bit 14, withhinged reciprocating pad assembly 1314 and adds compliance 1327 in padassembly 1314 drive mechanism. As one of ordinary skill in the art wouldappreciate on reading this application, DLP system 1300 could also beimplemented with integral drill bit/drive shaft as described throughoutthe application.

Drill string 1300 with Dynamic Lateral Pad includes radial cam race 1303that encircles the outer perimeter of bit box portion 1304 of driveshaft 1302. During steering of the drill string, drill bit 14 and driveshaft 1302 including cam race 1303 rotate relative to the generallynon-rotating (during steering of the drill bit) pad assembly 1314, padcarrier 1320, retainer 1324, housing 1322 and the remaining drill stringcomponents (not shown) terminating at the proximal end generally at ornear the surface of the earth. The radial thickness of radial cam race1303 alternates between one or more minimum and maximum thicknesses andthe profile of cam race 1303 may include one or more cam race profilefeatures including all of the types presented elsewhere in thisapplication. As previously discussed, at maximum cam race 1303 radialthickness, pad assembly 1314 is fully extended to push against thewellbore wall of formation 1350 to steer the bit in the desireddirection. However, in this embodiment an elastic element 1327 such as arubber pad, Belleville washers or machine springs is located between camfollower 1315 and pad 1316 to provide compliance in the actuator, tolimit pad assembly 1314 force and allow pad assembly 1314 to temporarilycollapse to prevent potential interference between drill string 1300with Dynamic Lateral Pad and formation 1350.

View 1391 is a section view of pad assembly 1314 interacting withformation 1350 at three positions. Position 1 illustrates a fullyretracted pad assembly 1314 with cam race 1303 at a minimum andpresenting pad 1316 to be flush or possibly slightly inset with respectto the outer diameter of raised section 1326 of pad carrier 1320. Inposition 1, force A_(L) and added resultant force B_(L) are zero andaxis of rotation CL₁ is in a neutral position generally near the centerof borehole CL_(B) and not affected by pad extension. Position 2illustrates extended pad assembly 1314 with the radial thickness of camrace 1303 approaching or at a maximum. Pad 1316 of pad assembly 1314 ispressing against formation 1350 but elastic element 1327 has not beencompressed beyond the pre-load force of elastic element 1327. Inposition 2, force A_(L) is a function of such things as drill stringmechanics, hole angle and bit characteristics but, in position 2 elasticelement 1327 was defined to be not compressed beyond the pre-load force,therefore the magnitude of force A_(L) and added resultant force B_(L)are limited to the magnitude of the preload on elastic element 1327. Inposition 2, axis of rotation CL₂ is offset from neutral position CL_(B)in the target direction by the length of pad assembly 1314 extension dueto the increased radial thickness of cam race 1303. Position 3illustrates extended pad assembly 1314 with cam race 1303 at a maximumthickness with pad assembly 1314 fully collapsed and sharing the lateralload with raised section 1326 of pad carrier 1320. In position 3, themagnitude of force A_(L) is equal to the force required to fullycollapse pad assembly 1314 but is largely irrelevant as the drillingactions and conditions, largely irrespective of pad assembly 1314 forceA_(L), are controlling the forces on the bit including added forceB_(L). Additionally, axis of rotation CL₃ has returned to near “neutral”position CL_(B) just offset by clearance distance D′ that is equal todistance D, the distance between raised section 1326 and wall offormation 1350 at position 1.

View 1390 is an isometric view of the distal end of drill string 1300with Dynamic Lateral Pad. This view shows pad 1316 with hinge pin 1318oriented parallel to drill string 1300 axis of rotation CL. Hinge pin1318 is supported by mounting provisions 1329 as are well known in theart. Hinge pin 1318 mounting provisions 1329 are located as shown inraised section 1326 of pad carrier 1320. Hinge pin 1318 is alsoconnected using well-known mounting provisions 1328 as part of pad 1316.In operation, pad 1316 pivots on hinge pin 1318 allowing controlledradial movement of pad assembly 1314 as cam race 1303 rotates under andthen away from cam follower 1315.

FIG. 14 provides a section view of drill string 1400 with DynamicLateral Pad (DLP) with a magnetic actuator and conventional bit 14 atdistal end 1452. Similar to drill string 1300 described above, drillstring 1400 includes the components described by drill string 12(FIG. 1) positioned above bearing package 24 with the possible exceptionof bend 35 that may or may not be included depending on the desiredaggressiveness of the drilling objectives. Returning to FIG. 14, drillstring 1400 also includes bearing housing 1322 connected to the distalend of transmission housing 36 (FIG. 1) and drive shaft 1402, inclusiveof bit box 1404 and magnets 1412 and 1414, connected to the distal endof transmission drive line 38 (FIG. 1). Drill bit 14 is connected to bitbox portion 1404 of drive shaft 1402 by API connection 37. Drill string1400 further includes pad carrier 1420 with slot 1421. Operationallypositioned in slot 1421 is pad 1416 including magnet 1413 and containinghinge portion 1418 with fixed mounting provision 1419 fixedly connectingpad hinge portion 1418 to pad carrier 1420. Pad carrier 1420 is fixedlymounted to bearing housing 1322 with retainer 1324 and torsion lock pin1323 engaging axial slot 1325 cut into bearing housing 1322.

While sharing many components with DLP drill string 1300 (FIG. 13), andproviding similar pad extension and retraction as DLP drill string 1300,drill string 1400 with Dynamic Lateral Pad utilizes fixed mountingprovision 1419, which may be a weld, adhesive, chemical bonding, or thelike to fixedly connect cantilevered spring hinge portion 1418 of pad1416 to pad carrier 1420 and utilizes a magnetic drive mechanism toprovide locomotion for reciprocating pad 1416. The magnetic drive,described below, provides a non-contacting and compliant drivemechanism. As one of ordinary skill in the art would appreciate onreading this disclosure, the DLP system 1400 could also be implementedwith integral drill bit/drive shaft as described throughout theapplication.

Drill string 1400 with Dynamic Lateral Pad includes a magnetic actuatorto extend pad 1416. Pad magnet 1413 is fixedly attached to pad 1416 withnorth magnetic field N_(P) of pad magnet 1413 orthogonal to and orientedaway from axis of rotation CL. Extend magnet 1412 is fixedly attached tobit box portion 1404 of drive shaft 1402 with north magnetic field N_(E)of extend magnets 1412 orthogonal to but oriented in the direction ofaxis of rotation CL. As drill bit 14 and drive shaft 1402 including bitbox portion 1404 and extend magnet 1412 rotate relative to the generallystationary (while directional drilling) pad carrier 1420, pad 1416including pad magnet 1413, retainer 1324 and bearing housing 1322;extend magnet 1412 rotates under pad 1416 and pad magnet 1413. Becausethe polarity of pad magnetic field NP is opposed to the polarity ofextend magnetic field N_(E), as proximity and alignment of pad magnet1413 and extend magnet 1412 increase, pad 1416 is forced outwardly withforce A to push against the formation creating an opposing force B indrill bit 14 to steer the bit in the desired direction. As extend magnet1412 rotates away from pad magnet 1413, alignment and proximity decreaseand the magnetic force decreases. As one of ordinary skill in the artwill now recognize on reading the disclosure, additional extend magnets1412 positioned on the perimeter of the bit box portion, or magnets witha longer arc length could be used to apply force to extend the pad for alonger portion of the revolution. Conversely, a magnet or magnets with ashorter arc length could be used to apply force to extend the pad for alesser portion of drill bit 14 revolution. Once extend magnet 1412sufficiently clears pad magnet 1413, either cantilevered spring hingeportion 1418 or the formation (not shown) or both act to retract pad1416 to the withdrawn position. Compliance is provided by mechanical fitas, by design, clearance is always provided between extend magnet 1412and pad magnet 1413, even if pad 1416 and pad magnet 1413 do not move asextend magnet 1412 rotates under pad 1416 and pad magnet 1413.Maintaining clearance, regardless of the orientation of extend magnet1412 and pad magnet 1416 prevents the creation of an interferencecondition between drill string 1400 with Dynamic Lateral Pad and theformation (not shown). Magnets materials for these embodiments includebut are not limited to iron, ferromagnets, rare earth magnets such assamarium-cobalt and neodymium-iron-boron (NIB) and electromagnets.Magnets are attached using one or more means such as a chemicaladhesive, mechanical fastener or interference fit

In addition to cantilevered spring hinge portion 1418 or the formation(not shown) or a combination of both acting to retract pad 1416 to thewithdrawn position, a third method to retract pad 1416 is possible byuse of one or more retract magnets 1414 also mounted on the perimeter ofbit box portion 1404 of drive shaft 1402 with north magnetic fields NRorthogonal to and oriented away from the direction of axis of rotationCL (the opposite orientation as extend magnet 1412). As drill bit 14 anddrive shaft 1402 including bit box portion 1404 and retract magnets 1414rotate relative to the generally stationary (while directional drilling)pad carrier 1420, pad 1416 with pad magnet 1413, retainer 1324 andbearing housing 1322; retract magnets 1414 rotate under pad 1416 and padmagnet 1413. Because the polarity of pad magnetic field N_(P) iscongruent with the polarity of retract magnetic field N_(R), asproximity and alignment of pad magnet 1413 to retract magnets 1414increase, pad 1416 is attracted inwardly towards the retract magnets.Conversely, as retract magnet 1414 rotates away from pad magnet 1413,alignment and proximity decrease and the magnetic force decreases.

FIG. 14 provides a section view of drill string 1400 with DynamicLateral Pad (DLP) with extend magnet 1412 rotationally positioned suchthat pad magnet 1413 of pad 1416 and extend magnet 1412 are face to faceproviding magnetic force to extend pad 1416. View 1491 provides asection view of the actuator section of drill string 1400 with DynamicLateral Pad rotated 180 degrees and therefore rotationally positionedsuch that pad magnet 1413 of pad 1416 faces retract magnet 1414retracting pad 1416. View 1492 is a cross-sectional cut through thecenter of pad magnet 1416 providing an exemplary magnet configurationproviding about 45 degrees of extension and 300 degrees of retraction.View 1490 is an isometric view of the distal end of drill string 1400with Dynamic Lateral Pad further showing carrier slot 1421 and pad hingeportion 1418 with fixed mounting provision 1419 such as, but not limitedto a weld or brazed joint fixedly connecting pad hinge portion 1418 andpad carrier 1420. Alternatively, the pad and the carrier could also bemanufactured as a single piece using for example steel tubing, steel baror a metal casting.

FIG. 15 shows a section view of drill string 1500 with DLP and an axialhinged pad. Drill string 1500 is essentially identical to drill string1300 (FIG. 13 above) with a few notable exceptions. One exception isdrill string 1500 provides a pad 1516 mounted on pad carrier 1520 thatis mounted parallel to axis of rotation CL as opposed to the embodimentprovided in drill string 1300 where pad 1316 is mounted about the outercircumference of pad carrier 1320. Between the circumferential padmounting provided in in drill string 1300 and the axial pad mountingprovided in drill string 1500, one of ordinary skill in the art will nowrecognize, on reading the disclosure that, the orientation of a hingedreciprocating pad is not constrained to a single orientation. Inaddition to a circumferential orientation provided in drill string 1300and axial orientation provided in drill string 1500 above, one ofordinary skill in the art will now recognize that a hinged pad can beimplemented at virtually any angle about a physical or virtual cylinder,such as the pad carrier. Examples include a pad such as pad 1516 ondrill string 1500 rotated, with carrier slot 1521, 180 degrees alongaxis of rotation CL resulting in pad hinge 1518 mounted closer to distalend 1552 of drill string 1500. Similarly, while never intended to belimiting, pad 1316 of drill string 1300 is shown with hinge pin 1318leading rotation but hinge pin 1318 and the requisite mountingprovisions could be flipped 180 degrees on the horizontal with hinge pin1318 trailing rotation. Further, the pad could be rotated at virtuallyany angle off horizontal or off axis of rotation CL and could have aplurality of hinges. Alternative orientations for hinge mounting allowfor the potential to improve operational mechanics specific to a givendrilling environment. Examples include; more abrupt or less abrupt padextension and retraction, larger pad area in the generally cylindervolume, longer hinge portions within a given space allowing for morecomplex extension and retraction mechanism such as providing a fulcrum,adding compliance, and creating an alternative pad extension vector thatis more effective at rock removal than just the added side loadpreviously explained.

Another exception of drill string 1500 as compared to is drill string1300 is drill string 1500 includes hinge portion 1518 of pad 1516fixedly attached to carrier 1520, in this case weld 1519, as previouslypresented as part of drill string 1400. Another possible exception ofdrill string 1500 as compared to drill string 1300 is use of anon-descript cam follower 1515 that could be compliant or not. Also, theactuator could be of a type consistent with the magnet system presentedas part of drill string 1400, other actuators presented earlier orfollowing in this application and actuator alternatives that one ofordinary skill in the art will now recognize on reading the disclosure.FIG. 15 also includes view 1590, an isometric view of the distal end ofdrill string 1500 with Dynamic Lateral Pad identifying carrier slot1521.

FIG. 16A provides a section view of drill string 1600 with drill bitmounted Dynamic Lateral Pad (DLP). In this exemplary embodiment, drillstring 1600 includes the components described by drill string 12positioned above bearing package 24 with the possible exception of bend35 (FIG. 1) that may or may not be included depending on the desiredaggressiveness of the drilling objectives. Returning to FIG. 16A, drillstring 1600 also includes bearing housing 1322 connected to the distalend of transmission housing 36 (FIG. 1) and drive shaft 1602 inclusiveof bit box 1604 connected to the distal end of transmission drive line38 (FIG. 1). Drill bit 1606 is connected to bit box portion 1604 ofdrive shaft 1602 by API connection 37. Drill string 1600 furtherincludes cam sleeve 1620 and torsion lock pin 1323 to engage axial slot1325 cut into bearing housing 1322 and cam sleeve 1620 that is fixedlymounted to bearing housing 1322 with retainer 1324 and torsion lock pin1323 to prevent relative rotation between cam sleeve 1620 and bearinghousing 1322. The distal end of cam sleeve 1620 terminates with anexternal cam profile 1603 on the outer surface of cam sleeve 1620. Inaddition to multiple drill bit cutters 1612 shown as PDC type and morethoroughly described above, drill bit 1606 includes hinge pin 1618, apossible supplemental pad 1616 retraction apparatus (not shown) and pad1616 with cam follower portion 1617. Pad 1616 swings on hinge pin 1618and is operationally coupled to external cam race 1603 of cam sleeve1620 at cam follower portion 1617. Although not shown in FIG. 16A,exemplary supplemental pad retraction apparatus include, but are notlimited to, springs, magnets and scavenging hydraulics from mudflow. Anexample supplemental pad retraction apparatus is shown as spring 1725 inFIG. 17. Similar to previous discussions, cam race 1603 varies in radialthickness about the perimeter of cam sleeve 1603 causing pad 1616 toextend and retract by rotating in and out on hinge pin 1618. Consistentwith previous cam race descriptions, it is possible to have multipleundulations and multiple cam races with differing radial thicknesses andslopes.

Very similar to DLP string 600, cam sleeve 1620 of drill string 1600 isfixedly attached to bearing housing 1322 but the cam sleeve and bearinghousing could also be made to be integral or as one piece. As inprevious embodiments, bearing housing 1322 is fixedly connected to thedrill string components above (not shown) and are oriented as requiredto cause bit 1606 to advance drill string 1600 in the desired directionwhen drill bit 1612 is rotated and weight is applied. Cam sleeve 1620,bearing housing 1322 and the drill string above (not shown) aregenerally not rotating during directional drilling. As previouslydiscussed, to advance drill string, mud (not shown) is pumped from thesurface through drill string 1600 to cause rotor 30 (FIG. 1) to rotatedrive shaft 1602 and drill bit 1606 relative to cam sleeve 1620 andbearing housing 1322. As drill bit 1606 rotates, pad 1616 pivots onhinge pin 1618 due to cam follower portion 1617 of pad 1606 reacting tothe changing radial thickness of cam race 1603. As the thickness of camrace 1603 increases, pad 1606 rotates outward towards the formation wall(not shown) in the direction of arrow A. Upon contact to the formationwall (not shown) the outward rotation of pad 1616 pushes bit 1606 in theopposite direction as shown by arrow B. The added force results inadditional formation removal in the direction of arrow B. Drill string1600 in FIG. 16A illustrates pad 1616 _(E) outwardly rotated on pin 1618in an extended position with cam follower portion 1617 of pad 1606positioned at cam race 1603 _(E) oriented to a maximum thickness.Conversely, view 1691 illustrates cam race 1603 _(R) at a minimumthickness with pad 1616 _(R) and rotated to the retracted position. Inthis example, pad 1616 contact with the formation wall (not shown)causes retraction of pad 1616 as the bit rotates away from a maximumthickness of cam race 1603. View 1690 is an isometric view of the distalend of drill string 1600.

FIG. 16B shows drill string 1692 as identical to drill string 1600 (FIG.16A) except drill string 1692 includes pad cutters 1614 on pad 1616 c(shown as 1616 _(CE) and 1616 _(CR)). Operationally, drill string 1692and drill string 1600 are identical as extended pad 1616 _(CE), uponcontact with the formation wall (not shown), the outward rotation of pad1616 as shown by arrow A pushes bit 1606 in the opposite directioncausing added formation removal in the direction of arrow B. However,when pad 1616 _(C) is in the extended position, cutters 1614 on pad 1616_(C) of drill string 1692 also cause added formation removal in thedirection of arrow A. Drill string 1692 in FIG. 16B illustrates pad 1616_(CE) rotated and extended with cam follower portion 1617 of pad 1606positioned at cam race 1603 _(E) that is oriented at a maximumthickness. Conversely, view 1694 illustrates cam race 1603 _(R) at aminimum thickness with pad 1616 _(CR) rotated to the retracted position.View 1693 is an isometric view of the distal end of drill string 1692.While drill string 1600 shows bit mounted hinged pad 1616 to be axiallymounted, one of ordinary skill in the art will now recognize on readingthe disclosure that a bit mounted hinged pad could be formed as apartial helix (pure or a segmented approximation) and hinged at an angleprovided the retracted pad does not radially extend beyond a cylinderformed by bit gauge 210 (FIG. 2) and the helix does not wrap than about45 degrees about the perimeter of the cylinder also formed by bit gauge210.

FIG. 17 provides a section view of drill string 1700 with a moveableblade in the drill bit. In this exemplary embodiment, drill string 1700includes the components described by drill string 12 positioned abovebearing package 24 with the possible exception of bend 35 (FIG. 1) thatmay or may not be included depending on the desired aggressiveness ofthe drilling objectives. Returning to FIG. 17, drill string 1700 alsoincludes bearing housing 1322 connected to the distal end oftransmission housing 36 (FIG. 1) and drive shaft 1702 inclusive of bitbox 1704 connected to the distal end of transmission drive line 38 (FIG.1). Drill bit 1706 is connected to bit box portion 1704 of drive shaft1702 by API connection 37. Drill string 1700 further includes cam sleeve1720 and torsion lock pin 1323 to engage axial slot 1325 cut intobearing housing 1322 that is fixedly mounted to bearing housing 1322with retainer 1324 and torsion lock pin 1323. The distal end of camsleeve 1720 terminates with an internal cam profile 1703 on the innersurface of cam sleeve 1720. In addition to multiple fixed blades 1728with cutters shown as PDC type and more thoroughly described above,drill bit 1706 also includes a moveable bit blade 1716 with cam followerportion 1717, hinge pin 1718, and may include a supplemental retractionapparatus 1725. Moveable blade 1716 pivots on hinge pin 1718 and isoperationally coupled to internal cam race 1703 of cam sleeve 1720.Similar to previous discussions, cam race 1703 varies in thickness aboutthe perimeter of cam sleeve 1720 causing moveable bit blade 1716 toextend and retract by rotating in and out on hinge pin 1718. Consistentwith previous cam race descriptions, it is possible to have multipleundulations and multiple cam races with differing thickness and slopes.While in this exemplary embodiment supplemental pad retraction apparatus1725 is shown as a single coiled spring, the supplemental pad retractionapparatus could include a plurality of devices including differentspring types, magnets, scavenged hydraulics from mud flow or U shapedcam follower, the later to mechanically extend and retract blade 1716.

Similar to drill string 1600 (FIG. 16A), cam sleeve 1720 of drill string1700 is fixedly attached to bearing housing 1322, or could bemanufactured as a single piece, and the drill string components above(not shown) are oriented as required to cause bit 1706 to advance drillstring 1700 in the desired direction when drill bit 1706 is rotated andweight is applied. Cam sleeve 1720, bearing housing 1322 and theremaining drill string components mounted above (not shown) aregenerally not rotating during directional drilling. As previouslydiscussed, to advance drill string, drilling mud (not shown) is pumpedfrom the surface through drill string 1700 to cause rotor 30 (FIG. 1) torotate drive shaft 1702 and drill bit 1706 relative to cam sleeve 1720.As drill bit 1706 rotates, moveable bit blade 1716 pivots on horizontalhinge pin 1718 due to cam follower portion 1717 of moveable bit blade1706 reacting to the changing thickness of cam race 1703. As thethickness of cam race 1703 increases moveable bit blade 1716 above hingepin 1718 rotates inward, away from the formation wall (not shown) in thedirection of arrow D_(IN) compressing coil spring 1725. With hinge pin1718 acting as a fulcrum, the lower portion of moveable bit blade 1716moves outwardly towards the formation (not shown) by the relationship:travel distance out D_(OUT)−travel distance in D_(IN)*L₂/L₁ where L₁ isthe distance from the center line of hinge pin 1718 to the contact pointbetween cam race 1703 and cam follower portion 1717 and L₂ is thedistance from the center line of hinge pin 1718 to the cutter ofinterest. Outward motion D_(OUT) increases the rate of formation removalin the direction of arrow D_(OUT) for the portion of bit rotation wheremoveable bit blade 1716 is extended. As drill bit 1706 continues torotate, cam race 1703 moves away from maximum radial thickness allowingmoveable bit blade 1716 above hinge pin 1718 to rotate outwardly drivenby contact with the formation (not shown), spring 1725 or both. By now,one of ordinary skill in the art will now recognize on reading thedisclosure that more than one moveable blades 1716 could be implementedin a given drill bit, there could be multiple types of actuators such asthose detailed above and moveable bit blade 1716 could be implemented,similar to moveable pad 1616, at an angle as a pure or segmented helixwithin the limits detailed for drill string 1600. In addition, alsopresented above, an integral bit/drive shaft could replace theconventional bit and drive shaft with all the incumbent advantagesdescribed earlier.

Drill string 1700 in FIG. 17 illustrates moveable bit blade 1716 _(E)rotated to extend cutters 1714 out into the formation (not shown) withcam follower portion 1717 of pad 1706 located at a maximum thickness ofcam race 1703 _(E). View 1790 is an isometric view of the distal end ofdrill string 1700.

FIG. 18 provides a section view of the distal end of drill string 1800,an isometric view 1890 of the distal end of drill string 1800, end view1891 and cross-section view 1892 cutting through eccentric mud motorbearing housing 1822 at pocket portion 1824 and cover 1848. In thisexemplary embodiment, drill string 1800 includes all the componentsdescribed by drill string 12 positioned above bearing package 24 withthe possible exception of bend 35 (FIG. 1) that may or may not beincluded depending on the desired aggressiveness of the drillingobjectives. Returning to FIG. 18, drill string 1800 also includes aneccentric bearing housing 1822 with pocket portions 1824, axial bearings1840, lateral bearings 1842, electronics 1826, and cover 1848 fixedlyconnected to the distal end of transmission housing 36 (FIG. 1). Inaddition, drill string 1800 includes integral drill bit/drive shaft 1802with drive shaft portion 1803 and drill bit portion 1801 fixedlyconnected to the distal end of transmission drive line 38 (FIG. 1) androtatably coupled with eccentric bearing housing 1822 with bearings 1840and bearings 1842. Bearing housing 1822 is machined eccentrically, cast,forged or otherwise formed so that one side provides substantially morewall thickness but does not exceed the well bore diameter (not shown).The additional thickness created by this innovation may run the fullaxial length of the bearing housing or any portion there-of and extendcircumferentially from 10 to 160 degrees. The additional thickness mayalso be used to house an extendable pad, which could directionally drivethe drilling assembly towards a target, as well as sensors orelectronics to measure drilling parameters, batteries to powerelectronics, chemical sources or any combination of the afore mentioned.

Use of pockets containing electronics, sensors, chemical sources andbatteries in an eccentric housing above the bearing housing isrelatively common but this improvement provides for pockets 1824containing electronics 1826 and other components, in (eccentric) bearinghousing 1822. This is an improvement over the current art as it allowsplacement of electronics, sensors, batteries, chemical sources,extendable pads and other such components within around 8 to 18 inches,possibly closer, to the terminal cutting structures of drill bit portion1801 of integral drill bit/drive shaft 1802. In addition to positioningcomponents closer to the cutting structure, the components are locatedin a section of drill string 1800 that does not rotate with bit 1801making for better connectivity as compared to current art that limitsplacement of sensors and electronics to locations above the motorbearings, above the entire motor or in locations connected to androtating with the drill bit. With electronics or other components notrotating with the bit, connectivity to other electronics, sensor andpower sources is in the drill string is greatly simplified compared tothe current art that generally requires sensors and electronicspositioned close to and rotating with the drill bit to provide their ownpower and communications through or around the motor. In situ powerrequires the assembly to lengthen and electronic communications throughor around the motor is generally complex, expensive (cost and power) andoften comes with significant communications bandwidth limitations.Utilizing a conventional drill bit and drive shaft in lieu of theintegrated drill bit/drive shaft 1802 with an eccentric mud motorbearing housing 1822, as frequently discussed above, would also be asignificant improvement but comes with some length penalty, perhapsdoubling the distance to the bit cutting structure as detailed in FIGS.3A and 3B.

As described herein, the numerous DLP systems and DLC systems providepads or cutters on the drill bit associated with the drill string.Locating the DLP or DLC on the drill bit in certain embodiments providesthe structures as close to the cutting structures on the drill bit aspossible, which provides certain advantages, some of which are explainedherein. Drilling strings may be provided consistent with the technologydescribed herein with DLP systems and DLC systems mounted removed fromthe drill bit but placed on the housing of the drill string below thepower section 20 (see FIG. 1). For example, in certain embodiments, aDLP system may be provided on the drill bit and a complementary DLPsystem may be provided on the transmission housing 36 (see FIG. 1).Similarly, a DLP system may be provided on the bearing housing 42 (seeFIG. 1) and a DLC system may be provided on the transmission housing 36(see FIG. 1). Thus, depending on the drilling conditions and rockformation, the DLPs and DLCs described herein may be located on thedrill bit, the drill string housing below the power section, or acombination thereof.

FIG. 10B provides a side view 1000 of the distal end of an exemplaryDual Rotating Cutting Structure (DRCS) drilling system. FIG. 10Cprovides cross-sectional view 1092 of the exemplary Dual RotatingCutting Structure (DRCS) drilling system provided in FIG. 10B. Dualrotating cutting structure systems may be referred to as the DRCS systemor dual rotating cutting structure herein. FIG. 10A provides partialsection views of two exemplary embodiments of drill strings including adual rotating cutting structure. One embodiment is a DRCS drill stringwith no bend (DRCS_(no bend)) 1090 and the second is a DRCS drill stringwith a bend (DRCS_(w-bend)) 1091. Both drill strings include powersection 1002, transmission section 1004, bearing section 1006 with outercutting structure portion 1030, and integral drill bit/drive shaft 1028(reference FIG. 10C) with inner cutting structure portion 1020. Whilepresented with integral drill bit/drive shafts, both drill strings couldutilize a conventional bit and drive shaft. DRCS drill string with abend (DRCS_(w-bend)) 1091 also includes bend 1008, generally at or nearthe junction of transmission housing 1014 and bearing housing 1016.

Referencing FIG. 10A unless otherwise noted, DRCS drill string with nobend (DRCS_(no bend)) 1090 and DRCS drill string with a bend(DRVS_(w-bend)) 1091 both comprise power section 1002 including motorstator housing 1012 and motor rotor 1010 that rotates inside motorstator housing 1012 when mud flows from the surface. Motor housing 1012is rigidly coupled to the drill string above (not shown) that extends tothe surface. Transmission section 1004 includes transmission housing1014 and transmission driveline 1018 that rotates inside of transmissionhousing 1014. The distal end of motor housing 1012 is rigidly coupled totransmission housing 1014 with transmission driveline 1018 rigidlyconnected to the distal end of motor rotor 1010. Bearing section 1006includes bearing housing 1016 with outer cutting structure portion 1030,a bearing assembly (not shown), drive shaft cap 1047 (partially shown)and integral drill bit/drive shaft 1020 (reference FIG. 10C). Bearinghousing 1016 is rigidly connected to the distal end of transmissionhousing 1014. Integral drill bit/drive shaft 1020 is rotatably coupledto bearing housing 1016 through the bearing assembly (not shown) and isrigidly connected to the distal end of transmission driveline 1018through drive shaft cap 1047. Outer cutting structure portion 1030 ofbearing housing 1016 is essentially hollow (reference FIG. 10C) to allowintegral drill bit/drive shaft 1028, potentially including inner cuttingstructure portion 1020, to rotate within and with respect to the outercutting structure portion 1030. As explained above, the drill stringlocated the power section 1002 is rigidly coupled to outer cuttingstructure portion 1030 of bearing housing 1016 through motor statorhousing 1012 and transmission housing 1014, and it should now be clearouter cutting structure 1030 rotates with the drill string.

Again referencing FIG. 10A and starting at power section 1002; motorrotor 1010 (absent rotor catch 18 shown in FIG. 1) is essentially notconnected at proximal end 1048 but the distal end of the rotor isrigidly coupled to transmission driveline 1018. The distal end oftransmission driveline 1018 is rigidly coupled to integral drillbit/drive shaft (reference FIG. 10C) that includes inner cuttingstructure 1020 terminating at distal end 1046 of drill strings 1090 and1091.

With reference to FIG. 10B, an expanded side view of dual rotatingcutting structure system 1000 used with DRCS drill string with no bend(DRCS_(no bend)) 1090 and DRCS drill string with a bend (DRCS_(w-bend))1091 is provided showing inner cutting structure 1020 including blades1021 containing cutters 1022, interrupted gauge pad 1024 and junk slots1026 rotating inside of the outer cutting structure as shown by arrowsR_(I). Also shown in FIG. 10B, is outer cutting structure 1030 includingblades 1031 containing cutters 1032, interrupted gauge pad 1034, junkslots 1036 and interrupted follow guide 1038 that rigidly connects tobearing housing 1016 (and the drill string above) rotating with thedrill string above as shown by arrow R_(O)

As will be explained further below, dual rotating cutting structuresystem 1000 may be useable as a straight hole drilling assembly or aspart of a directional drilling assembly. By way of background, a cuttingstructure of a drill bit generally creates the wellbore size desired asthe wellbore extends into the formation, which may comprise rock andother mineral layers. The DRCS system provides at least two, essentiallyindependent, cutting structures/cutter sets that operate concurrently tocreate one wellbore. The two cutting structures generally operate atdiffering rotation rates to most effectively drill the wellbore.Generally, DRCS 1000 system includes an inner cutting structure 1020 andan outer cutting structure 1030. In certain embodiments, for example,inner cutting structure 1020 will rotate at a higher rate of rotationthan outer cutting structure 1030. In other embodiments, for example byreversing the pitch angle of rotor 1010 and motor housing/stator 1012,inner cutting structure 1020 will rotate at a lower rotation rate thanouter cutting structure 1030. In a further embodiment inner cuttingstructure 1020 and outer cutting structure 1030 can rotate in oppositedirections for example by again reversing the pitch angle on rotor 1010and motor housing/stator 1012 and operating mud motor 1002 at a rotationrate greater than the rotation rate of the drill string. In a furtherembodiment, inner cutting structure 1020 and outer cutting structure1030 can be made to rotate at essentially the same rotation rate forexample by rotationally locking the two cutting structures whilebypassing flow around the rotor or not.

One unique feature of the technology of the present application withrespect to DRCS system 1000 is the inner cutting structure 1020 and theouter cutting structure 1030 may include multiple types of cutters. Asdescribed above, cutting structures may take many forms, such as, forexample, polycrystalline diamond cutters (PDC), roller cones (RC),impregnated cutters, natural diamond cutters (NDC), thermally stablepolycrystalline cutters (TSP), carbide blades/picks, hammer bit (a.k.a.percussion bits), etc. or a combination thereof. DRCS system 1000 mayhave a conventional drill bit that is, for example, a roller cone, andan outer cutting structure that is a natural diamond cutter. Othercombinations are possible as well such as having identical drill cuttingstructures for the inner and outer cutting structures. The inner orouter cutting structures may mix different rock destroying mechanismssuch as an inner cutting structure with PDC and impregnated diamond oran outer cutting structure with natural diamond and roller cones or anycombinations of the aforementioned rock destruction mechanisms.

Also unique to DRCS system 1000 is the use of a drilling mud motor thathas the inner bit/cutting structure integrated monolithically with themud motor drive shaft. This configuration provides for a shorterdrilling assembly that is desirable for many reasons. For example, thefarther a drill bit face/cutting structure is located from thesupporting radial bearings in or below the mud motor, the greater themoment force. This greater force leads to earlier bearing wear, whichleads to reduced drill bit stabilization and accelerated wear or damageto the drill bit/cutting structure. Another benefit of the integrateddrill bit/drive shaft is better rigidity of the drill bit/cuttingstructure and higher torque transmitting capacity than conventional mudmotor/drill bit connections that are typically 2⅜″ thru 7⅝″ regular APIconnections.

Another unique feature with DRCS system 1000 is the ability to use a (¼to 5 degrees) bent housing in DRCS drill string with bend 1091 (FIG.10A) to create an off-axis rotation of both inner 1020 and outer 1030cutting structures. This off-axis rotation creates a variable pivotingpattern at the cutting structure/rock engagements. In a drillingassembly without a bent housing such as DRCS drill string with no bend1090 (FIG. 10A) and conventional motor drill string 300 (FIG. 3A), thelow rotational surface speed of inner most cutters 1022 create drillinginefficiencies that limit the performance of the drilling system. Cutterrotational surface speed when under pure rotation (that is no lateralmotion) as can happen without a bend, is defined by the relationship:cutter rotation surface speed is equal to the RPM*2πr where RPM is therotational speed and r is the radius or distance of the subject cutterfrom the axis of rotation. As r approaches zero, the cutter rotationsurface speed approaches 0. Bent housing element 1008 reducesconventional inefficiencies by introducing enhanced multi axis motion atcenter cutters 1008 (generally PDC) to better fail the rock in thecenter of the wellbore. The enhanced multi axis motion effectivelyremoves the center cutter inefficiencies allowing for improved drillingefficiency of the entire system. This feature also improves the life ofthe PDC cutters

Another important aspect of DRCS system 1000 is the ability to use somecomponents of conventional steerable system 10 (reference FIG. 1) incombination with the described improvements for DRCS system 1000.Generally, the motor is selected to generate sufficient torque to rotateand power all of the cutting structures (conventionally the drill bit).For example, for an 8¾″ bit, the likely choice would be a 6″ OD rangemud motor. With DRCS system 1000, the mud motor power is only requiredto rotate the generally smaller diameter inner bit/cutting structure1020 as outer cutting structure 1030 is rotated by drill stringrotation. In this embodiment, much less power should be required and asmaller OD, shorter length and/or higher speed power section couldsuffice. As examples, a 6″ OD range mud motor but with a shorter powersection or a smaller OD power section. The benefit derived could be ashortened power section or additional space (adjacent, radial or axial)around or just above the power section is now available for placing avariety of measurement sensors and power sources more convenient to thedrill bit or cutting structures. This closer proximity can providebetter and more accurate data to make decisions related to the drillingefficiency, safety of the drilling operation and cost of the well.Another potential advantage of extracting less power from the drillingfluid is that more hydraulic power is now available to increase bit HSI(horsepower per square inch) for better hole cleaning. Based upon theabove teaching, one ordinarily skilled in the art could easily see thatDRCS system 1000 in this embodiment cannot create the active directionalchange made possible by certain features of conventional steerablesystem 10.

FIG. 10C shows an exemplary embodiment of dual rotating cuttingstructure system 1000 where inner cutting structure 1020 extends belowthe distal end of outer cutter structure 1030, contacting the formationto be drilled first and supported by axial bearings 1040 and radialbearings 1042. Outer cutting structure 1030 would then increase thewellbore diameter to the desired size as it removes undrilled formationabove inner bit or inner cutting structure 1020. As shown in FIG. 10Aand FIG. 10B, a unique feature of outer cutting structure 1030 isfollow-guide 1038 designed to enter hole just drilled by inner bit 1020and provide radial stabilization for outer cutting structure 1030 toenlarge the uncut portion of the wellbore. This follow-guide 1038 can bemade with junk slots 1036, similar to a PDC drill bit or it can be madeas a ring (not shown) that provides 360-degree wellbore contact withorifices and/or nozzles to allow cuttings and return fluid flow. Thedistal end of follow-guide 1038 may be angled or tapered to assuresmooth entry into the pilot hole cut earlier by inner cutting structure1020 and provides stability for outer cutting structure 1030 reducingthe chances of PDC cutter impact damage for outer cutters 1032. In atapered embodiment of the follow-guide (not shown), the proximal end ofthe taper may be extended slightly to a greater diameter than theabove-mentioned pilot hole and contain cutting elements. This allows thefollow-guide to radially centralize and axially stabilize as outercutting structure 1030 drills the uncut portion of the hole. Anotherbenefit of follow-guide 1038 is reduced loading on radial bearing 1042thus extending bit and motor life and effectiveness. As shown in FIG.10C, inner cutting structure 1020 can extend below outer cuttingstructure 1030, inner cutting structure 1020 can be substantially flushwith outer cutting structure 1030 as shown in FIG. 11, or inner cuttingstructure 1020 can be retracted relative to outer cutting structure 1030as shown in FIG. 12.

FIG. 19A is a cross-sectional view of a non-limiting, exemplaryembodiment is of a dynamic lateral pad system 1900 with one moveable pad1902. The illustration shows a cut away view of an integral drill bitand drive shaft 1904 and a moveable pad 1902 acted upon by a camfollowing mechanism 1906, some of which have been described hereinbefore. During slide mode drilling, the moveable pad 1902 will extendand retract based on the cam following mechanism 1906 and the cam race1908 geometry. When the moveable pad 1902 is in the extended position,the exterior surface engages the sidewall of the wellbore creating adirectional bias. When the moveable pad 1902 is in the retractedposition, the moveable pad 1902 is generally flush with the housing1910, although in certain embodiments it may extrude slightly and/or berecessed. The integral drill bit and drive shaft 1904 rotates relativeto the generally non-rotating drill string housing 1910 during steeringof the of device. The integral drive shaft and drill bit 1904 has acontinuous circumferential cam race 1908 with variable radial depth. Onthe outer housing of the bottom hole assembly, at least one recess 1912is formed in the housing 1910 for the moveable pad 1902 to extend andretract. As shown in FIG. 19B, the moveable pad 1902 as shown in theillustration has two opposing locking tabs 1914 to retain the moveablepad 1902 within the recess 1912. In certain embodiments, exterior plates1916 are attached with bolts (not specifically shown) or similar methodover top of the tabs to retain the moveable pad 1902 operatively in therecess while allowing the pad to freely extend and retract within agiven range of travel. The moveable pad 1902 may be hollow toaccommodate an elastic member 1918 (FIG. 19A), such as, a coned-discspring stack as shown, which is commonly referred to as a Bellevillespring. The moveable pad 1902, optionally, has a hole or bore to allowfluid communication between the outer housing and the inner housingprimarily to provide flush cooling and to help lubricate the surfacebetween the moveable pad and a cam follower cup 1920. The coned-discspring stack serves multiple functions. One exemplary function may be toprovide compliance to varying wellbore internal diameters. Anotherexemplary function may be to provide shock load dampening. Anotherexemplary function may be to provide a calibrated maximum force on themoveable pad 1902. Another exemplary function may be to act as afailsafe allowing the moveable pad 1902 to revert to a retracted safecondition in the event of an unexpected interference fit with theborehole thus protecting the mechanism. Any given embodiment may includesome, all, none, or other of these functional example. An optionalgasket (not specifically shown) can be positioned in a groove of theinner diameter of the recess 1912 to centralize the moveable pad 1902and mitigate fluid flow between the recess 1912 and the moveable pad1902. Underneath the coned-disc spring stack is the cam follower cup1920 (FIG. 19A). The cone follower cup has a mating surface tooperatively transfer force from the cam follower to the moveable pad.The cam follower cup 1920 can be a roller ball, tapered roller, cylinderroller, sliding pad or similar cam following system. It should be notedthat the cam race 1908 has an extended width to accommodate axialdisplacement due to potential wear from the ball bearing thrust stacktypical in most bottom hole assemblies. It should also be noted that itis possible to have any variety of cam profiles, ramp build and decayrates or timing schemes formed on the cam race. Unique to thisconfiguration is that as the pad is extended, the tabs act to provide acounter force to retract the pads back into the housing as the camfollower force is relieved. It can be appreciated that more than one padmay be used. It can also be appreciated that pads may be arranged in anyvariety of positions both radially and colinearly to create differentbiasing, steering and timing options, some of which are exemplifiedherein. It can also be appreciated that a box pin connectionconfiguration to attach the bit may also be used for this embodiment.

With reference now to FIGS. 19C and 19D, a non-limiting, exemplaryembodiment 1930 to the embodiment 1900 is provided. The non-limiting,exemplary embodiment 1930 uses an integral drill bit and drive shaft1932 and a cam following mechanism 1934 acting upon a moveable pad 1936allowing it to extend and retract within a recess 1912. This designdemonstrates an alternative moveable pad 1936 assembly. The generallycylindrical moveable pad 1936 assembly uses an integral cantilever shaft1938, which is attached to the housing 1940. The cantilever shaft issecured to the housing using bolts 1942 or similar attachment means. Thecantilever shaft 1938 operatively provides a retraction force on the padto return it back into the recess 1912. A gasket 1944, such as anO-ring, is seated in an inner diameter groove of the cylinder tocircumferentially support the cantilever arc path of the pad as well asmitigate fluid flow in the recess 1912 channel between the moveable pad1936 and cylinder. The moveable pad 1936 may include a hole 1937allowing fluid communication between the outer and the inner housingprimarily to provide flush cooling and to help lubricate the surfacebetween a ball 1946 and the cam follower cup 1948. It can be appreciatedthat the pad mechanism can be positioned in other orientations, such as180 degrees on the housing from what is illustrated, such that theattachment of the cantilever shaft can be toward the cutting structure.It can also be appreciated that more than one cam following pad can bemounted on the housing. It can also be appreciated that multiple padscan be placed in different radial positions and with the option ofdifferent timing schemes. It can also be appreciated that a box pinconnection configuration to attach the bit could also be used for thisembodiment.

FIGS. 19E and 19F show a DLP system 1950, which is similar to the abovein certain aspect. In particular, the DLP system 1950 uses an integraldrill bit and drive shaft 1952, and a cam following mechanism 1954acting upon a plurality of moveable pads 1956, in this exemplaryembodiment, allowing them to extend and retract within correspondingrecesses 1912. The DLP system 1950 provides three moveable pads 1956collinearly positioned on the housing 1958. Each of the moveable pads1956 is partitioned with two outer diameters such that an exteriorlocking retention plate 1960 on each side will restrict the moveablepads 1956 from over extending. Depending on the space between pads, andother design factors, one exterior locking plate 1960 could be used tolock two pads or more pads. In some embodiments, each moveable pad 1956would have one or more locking plates 1960. The locking plate 1960 couldalso be a ring or other locking structure surrounding each pad. Asdescribed in the previous embodiment, each pad may use a fluidcommunication hole between the outer housing and the inner housingprimarily to provide flush cooling and to help lubricate the surfacebetween the ball and the cam follower cup 1954. This embodiment allowsfor the advantageous rotation of the pads. Active rotation could beinduced using a modified cam race profile creating a bias to spin thecam follower, spring, and pad. Alternatively, pad rotation can beinduced via various contoured patterns of grooves or channels on the padface. Consistent with previous cam race descriptions, it is possible tohave multiple undulations as well as differing thickness and slopes. Itcan also be appreciated that any number of timing patterns between padsas well as ramp build and decay rates for each pad can be configureddepending on the drilling application. It can also be appreciated that abox pin connection configuration to attach the bit could also be usedfor this embodiment.

FIGS. 19G and H provide an exemplary DLP system 1970 a mandrel 1972 witha box pin connection 1974 to attach a drill bit 1976 and a cam followingmechanism 1978 acting upon a plurality of cylindrical, movable pads 1980allowing it to extend and retract within a recess 1912. In thisconfiguration, two moveable pads 1980 are collinearly positioned in twodifferent radial locations on the housing. As described in the previousembodiment, each individual pad 1980 will extend and retract specific toa prescribed cam profile. As described in the previous embodiment eachpad can optionally rotate via a biasing cam profile pattern, contouredgrooves and patterns on the pad or similar methods. It should be notedthat pads can be positioned in any number of patterns on the housing.Non-limiting and non-inclusive examples are collinear rows of pads,radial patterns of pads, helix patterns, symmetric clusters, asymmetricclusters, and pads in random positions on the housing. It can also beappreciated that any variety of extension and retraction patterns can beconfigured. Non-limiting and non-inclusive examples are the sequentialextension and retraction of a collinear group of pads, two or more padsextended with one or more retracted in a collinear group, sequentialtiming between pads in different radial positions and at least two padsextending or contracting at the same time in different radial positions.It should be noted that any number of custom pad extension andretraction patterns can be customized based on the drilling applicationand bottom hole assembly configuration. It will be appreciated thatcertain pad extension and retraction patterns can induce favorablevibrations to reduce drill string friction with the borehole wall,especially during build and lateral drilling. Certain pad extension andretraction patterns could induce advantageous drill string rocking tofacilitate well bore cleaning and cuttings removal. It should be notedthat an integral drill bit and drive shaft configuration could also beused in place of a box pin connection to attach the drill bit.

Course Holding for Rotary Mode Steerable Motor Drilling

Oil and gas well directional drilling is commonly accomplished with abent housing positive displacement motor assembly. Course correctionsusing subject assemblies are accomplished by orienting the bend of theassembly and allowing the assembly to drill ahead in “slide mode”without rotation of the drill pipe. When a survey ascertains that thedrilling is progressing on the chosen course, the assembly is put into“rotate mode,” in which the assembly drills forward via rotation of thedrill pipe.

The goal in rotate mode is to continue forward along the achieved anddesired path. Drilling forward along the desired path is referred to as“neutral drilling.” In practice, over time the assembly typicallyexperiences a slight departure or drift from the chosen path. Thedeparture may be upwards (referred to as “build”), downwards (referredto as “drop”), or left and/or right (referred to as “turn” or “walk”).The deviation may be a combination of inclination change and orientationchange.

The deviation from neutral drilling is frequently referred to as the“tendency of the assembly” in rotate mode. When the cumulative departureor drift from the chosen path is too great, a correction must be made inslide mode to bring the assembly back to the chosen path. Eachcorrection slows drilling down and creates increased tortuosity in thewellbore. In a long lateral drilling section, the cumulative tortuositybrought about due to multiple corrections can produce excessive torqueand drag, which limits the length of lateral that can be drilled.

The specific directional tendency of the assembly in rotate mode isproduced by one or more of several different factors, including but notlimited to: bit torque, bit profile, bit gauge length, currentinclination, string torque, formation dip, formation properties,assembly stabilization, bend angle, weight on bit, rotational speed andinertia, and gravity.

A bend housing directional assembly drilling ahead in rotate mode maycreate an oversize hole due to the bend in the assembly. Higher bendangle assemblies generally create larger oversize hole diameters becausethe drill string rotation causes the drill bit to orbit at a greatercircumference around the hole centerline.

A bend housing assembly producing a directional tendency in rotatedrilling is exhibiting a preferential bias in the direction of thetendency. In other words, the assembly's cumulative center of rotationis biased in the direction of the tendency exhibited. Another way ofstating this is that the assembly tends to lean or push against thewellbore wall in the direction of the deviation tendency. The greaterthe rate of deviation, the greater the cumulative bias, which can betermed the deviation force.

The deviation force exhibited or experienced by the assembly is notnecessarily constant in frequency, direction, or strength. The assemblymay move forward for many revolutions of the drill string withoutexhibiting a deviation force interaction, or it may move forward with avarying direction of deviation force interaction forestalling for adistance a biased departure. Ultimately, the assembly will be morelikely to exhibit a greater frequency or strength of deviation force inthe direction of the directional tendency. It is the cumulative sum ofdeviation forces exhibited by the assembly that produces the directionaltendency of the assembly.

Predicting and trying to control or mitigate the directional tendency inrotate mode with a bend housing assembly has been a long-sought goal. Ininstances where a higher degree of bend was utilized, this goal has beeneven more difficult to achieve.

Introduced here, therefore, are assemblies that employ one or more motormandrel cam-driven Dynamic Lateral Pads (DLPs) to provide a restorationforce in opposition to the deviation force(s) of the rotating assembly.In certain embodiments, the DLPs are deployed generally on the bend sideof the assembly proximal to the drill bit and distal of the bend of thebend housing. The DLPs may deploy and retract one or more times permotor (mandrel) revolution depending on the mandrel cam configuration.The DLPs can be provided with a stroke that pushed them out to adiameter substantially equal to, or slightly greater than, the bitdiameter. When the assembly is biased against a hole wall, the deployedDLPs push against the hole wall with a greater force or frequency inopposition to the deviation bias direction to provide a restorativeforce to the assembly. The action of the DLPs can counter the deviationforce, thereby reducing or eliminating the directional tendency.

An example is provided as follows:

Motor (and Mandrel) Revolutions Per Minute(RPM)=240 (i.e., fourrevolutions per second)One DLP, One Camming Lobe=240 deployments of DLP per minute 32 DLPdeploys once every 0.25 secondsRotary (Outer Assembly) RPM=60 (i.e., one revolution per second)For each revolution of the assembly, the DLP will deploy four times. Insuch embodiments, deployment of the DLP may occur in 90 degreeincrements (e.g., once in each quadrant).

In a revolution of the assembly where a deviation bias of the assemblyoccurs, the deployment of the DLP in the quadrant of the deviation biaswill push against (e.g., tap or strike) the borehole wall providing arestorative force (also referred to as a “counter-deviation force”).Since the assembly in this instance is off center in the direction ofthe deviation bias, the deployed DLP will fail to touch, or at leastless forcefully touch, the borehole wall in the other three quadrants.To some degree, the location of the touch point can be altered bychanging the rotational speed of the housing, the rotary speed, or theflow rate (which changes RPM of the mandrel).

FIG. 20 provides a typical tool face angle chart or dial 2000. Dial 2000includes center point 2001, inclination/declination dividing line 2002,and left turn/right turn dividing line 2003. Dial 2000 reflects theaccepted definitions of build, right turn, drop, and left turn, as wellas the accepted angular definitions of deviation from neutral drilling.Note, for example, that 225° marks the dial angular value for equalvalues of drop and turn left.

FIG. 21A provides a cross-sectional view 2100 of an oversized rotarydrilled hole 2105 at the locations of a rotating bit gauge circumference2104. The cross-sectional view 2100 also shows neutral drilling centerpoint 2101 and generalized orbiting bit diameter center points 2102.Rotational circumference 2103 shows the rotational orbit of the bitdiameter center points 2102 as they rotate around the neutral drillingcenter point 2101. Note that the cross-sectional view 2100 (and thefeatures shown) are not necessarily to scale but are intended toillustrate the general concept of oversized drilling with a bend housingassembly (not shown).

FIG. 21B provides a detailed cross-sectional view of the hole area shownin FIG. 21A in neutral drilling mode. More specifically, FIG. 21B showsthe neutral drilling center point 2101 and generalized orbiting bitdiameter center points 2102. Rotational circumference 2103 shows therotational orbit of the bit diameter center points 2102 as they rotatearound the neutral drilling center point 2101.

FIG. 21C provides an alternative detailed cross-sectional view of thehole area shown in FIG. 21A after drilling has advanced some distance.In FIG. 21C, the neutral drilling center point is shown at 2101. Adeviation force, meanwhile, is shown at 2120. When the deviation force2120 is applied, the center point of the rotating bit diameter willshift to the advanced and now deviated location 2111. The deviationshown is generally indicative of drop and left turn of approximately225° on the tool face dial.

FIG. 22 provides a generalized and exaggerated comparative side view2200 of a neutral drilling borehole 2206 and a drop deviation borehole2216. Neutral drilling borehole 2206 is shown proceeding along neutraldrilling centerline 2201. When a downward deviation force 2220 isapplied, however, drilling will result in a deviated borehole 2216 alongdeviated drilling centerline 2211.

FIG. 23 provides a generalized and exaggerated comparative top view 2300of a neutral drilling borehole 2306 and a left turn deviation borehole2316. Neutral drilling borehole 2306 is shown proceeding along neutraldrilling centerline 2301. When a leftward deviation force 2320 isapplied, however, drilling will result in a deviated borehole 2316 alongdeviated drilling centerline 2311.

FIG. 24 provides an end view 2400 of a neutral drilling borehole. Centerpoint 2401 is shown, as is borehole diameter 2405. As shown in FIG. 24,neutral drilling will result in a roughly consistent borehole thatproceeds along a single path.

FIG. 25 provides an end view 2500 of a deviated dropping and leftturning borehole 2516. Because the drilling apparatus is under theinfluence of deviation force 2520, the borehole 2516 will drop to theleft along centerline 2511. The deviation shown in FIG. 25 is generallyindicative of drop and left turn of approximately 225° on the tool facedial.

FIG. 26A provides an isometric view 2600 of a partial section of a basicDynamic Lateral Pad (DLP) assembly consistent with the technology of thepresent application. The DLP assembly may have a lower housing 2607 thatincludes a DLP blade 2631 and a DLP 2630 (also referred to as a “pad” or“DLP pad”). In FIG. 26A, the DLP 2630 is shown in the retractedposition. Distal of lower housing 2607 is the lower mandrel 2608. Thelower mandrel 2608 may include a connection cavity 2609 for receiving adrill bit (not shown).

FIG. 26B provides a cross-sectional view of a Dynamic Lateral Pad (DLP)assembly taken through section A-A of FIG. 26A. FIG. 26B shows the lowerhousing 2607 with the DLP blade 2631 and retracted DLP 2630. Thecross-sectional view does not show the mandrel or the activationmechanism of the DLP 2630. The activation mechanism of the DLP 2630 isfurther described above (e.g., with respect to FIGS. 13-15).

FIG. 27A provides a cross-sectional view 2700 of an oversized rotarydrilled hole 2705 at the location of a rotated cross section of adeployed Dynamic Lateral Pad (DLP) 2740 during neutral drillingconsistent with the technology of the present application. For clarity,only the cross section of the deployed DLP 2740 and DLP blade 2731 areshown. Dashed lines 2732 are not structural features but instead areshown for reference. The apex of each pair of dashed lines 2732converges toward the center of the assembly at each portion of rotationshown. Circle 2703 shows the oversized rotation of orbit of the assemblyaround the center point 2701 of the borehole.

FIG. 27B provides a cross-sectional view 2700 of the oversized rotarydrilled hole 2705 of FIG. 27A with a rotated and retracted DynamicLateral Pad (DLP) 2730 during a single rotation during neutral drilling.For clarity, only the cross section of the retracted DLP 2730 and DLPblade 2731 are shown. Dashed lines 2732 are not structural features butinstead are shown for reference. The apex of each pair of dashed lines2732 converges toward the center of the assembly at each portion ofrotation shown. Circle 2703 shows the oversized rotation of orbit of theassembly around the center point 2701 of the borehole.

FIG. 28 provides a cross-sectional view 2800 of an oversized rotarydrilled hole 2805 at the location of a rotated cross section of adeployed Dynamic Lateral Pad (DLP) 2840 experiencing a deviation bias.For clarity, only the cross section of the deployed DLP 2840 and DLPblade 2831 are shown. Dashed lines 2832 are not structural features butinstead are shown for reference. The apex of each pair of dashed lines2832 converges toward the center of the assembly at each portion ofrotation shown. Circle 2803 shows the oversized rotation of orbit of theassembly around the deviated center point 2801 of the borehole.

In some cases, a deviation force 2820 will act on the assembly duringdrilling. When the DLP 2840 is deployed, engagement of the DLP 2840 withthe oversized borehole 2805 will result in a restoration force 2821 thatat least partially counters the deviation force 2820. In this example,the deployed DLP 2940 is shown engaging the wall of the oversizedborehole 2805 generally at the location indicated by bracket 2842 indirect response to the deviation force 2820. This example shows thedeviation force 2820 generally towards 225° and the restoration force2821 in direct opposition to the deviation force 2820. Depending on thetiming of the rotation of the housing (not shown) and the deploymentcycle of the DLP 2840, two individually less forceful engagements couldoccur, for example at 180° and 270°. In combination these twoengagements could provide a combined restoration force comparable to therestoration force 2821 shown in FIG. 28. In such embodiments, eachindividual restoration force may be said to indirectly oppose thedeviation force 2820, while the combined restoration force may be saidto directly oppose the deviation force 2820. Although FIG. 28 shows thedeviation force 2820 generally towards 225° degrees, it should beunderstood that the deviation force 2820 may by in any tool facedirection around the tool face dial and that the restoration force 2821provided by the deployed DLP 2840 will respond in opposition to thedeviation force.

FIG. 29 provides a generalized top view 2900 of a borehole illustratingthe interaction of weight on bit drilling force 2951, deviation force2920, and restoration force 2921 over a brief period of time as shownalong 2953 and brief distance as shown along 2954. This example shows aplan view of drilling process along a centerline 2911 as the directionof the resultant force 2952 shifts slightly (e.g., between left turn270° and right turn 90° as marked by azimuth left turn/right turn line2949) under the influence of the deviation force 2920 and restorationforce 2921. This plan view only takes into account azimuth since it is atwo-dimensional graphic, but it should be noted that the same factorsmay apply to inclination or a combination of inclination and azimuth.Looking along timeline 2953 at the interval marked “1st Second,” thedrilling path along the centerline 2911 is demonstrating neutraldrilling. However, at the end of the “1st Second” interval, a deviationforce 2920 commences pushing the centerline 2911 of the drilling path tothe left towards the 270° direction on azimuth line 2949. Midway throughthe “2nd Second” interval, a restoration force 2921 pulses from theengagement of the DLP with the hole wall (not shown) and begins to pushthe resultant force 2952 back towards 90° on the reference azimuth line2949. Continuing pulses of restoration force 2921 can be seen in the“3rd Second” interval and “4th Second” interval to overcome thedeviation force and return the centerline 2911 to its original course,as shown in the “5th Second” interval. A somewhat similar cycle can beseen occurring in the “6th Second” interval and “7th Second” interval.

The data presented in FIG. 29 is based on the previously discussedexample parameters of 60 RPM for the housing, 240 RPM for the motormandrel, a single DLP, and a single activating cam lobe on the mandrel.The data also assumes a 60 foot per hour penetration rate. While theseparameters are fairly typical, they are by no means required toimplement the technology of the present application. The data may varyas these parameters change.

As can be seen in FIG. 29, in a short 7 second time span and a short1.4″ of drilling (as shown by the 0.200″ increments along drilleddistance line 2954), multiple cycles of deviation force 2920 andrestoration force 2921 can occur. The predominant force in any drillingscenario is the weight on bit drilling force 2951. However, thedirection of the drilling force may be modified by a deviation force aswas illustrated in FIGS. 22, 23, and 25. Deviation is discussed in termsof degrees per 100 feet, such as “4°/100.” As shown in FIG. 29, thedeviation force 2920 and restoration force 2921 come into play on a muchsmaller scale. Deviation can begin with an inception of a deviationbias. While the deviation bias does not directly translate the boreholelaterally, it can slightly bend or redirect the resultant force 2952 toshift the direction of the borehole as the drill bit drills ahead.

In certain embodiments, deployment of DLP(s) occurs with a frequencybased on the RPM of the motor and/or the number of cam lobes on themandrel. DLP deployment may not substantially engage the borehole wallduring neutral drilling. When the assembly is biased towards theborehole wall by a deviation bias, the DLP will begin to engage theborehole wall nearly instantaneously in direct response to the deviationbias, thereby providing a restoration force that pushes the assemblyback towards the original borehole centerline. The response can bepurely geometric and mechanical. Accordingly, unlike extremely expensiveand complicated Rotary Steerable Systems that require electroniccommunication means, feedback loops, and activation commands, thetechnology described herein may be constantly “active” but only providerestoration force when bias of the assembly brings DLP(s) into contactwith the borehole wall.

In a scenario where the deviation force overcomes the pulses ofrestoration force and succeeds in slightly modifying the drilling path,then a new path will be established as “neutral drilling.” The assemblywill respond to the new assembly bias to produce restoration force tothe most recent path. There is still significant value in the technologyeven in this scenario. For instance, an unresisted deviation bias thatwould ultimately produce a 4°/100′ deviation may be mitigated to only2°/100′. Without the technology described herein, a correction slide runmay be required after just 100′ of drilling. However, with thetechnology described herein, the driller may choose to drill ahead for200′ or more prior to making a correction. Fewer correction runstranslates into much greater lateral drilling length potential, easiercompletion running, and less production maintenance cost anddifficulties.

Depending on formation properties, drilling parameters, and experiencewith the DLP system described herein, an assembly designer may choose toincrease or decrease the amount of deployment extension of each DLP. Forinstance, in softer formations the assembly designer may want a greaterextension of the DLP to ensure it generates enough restoration force inresponse to a deviation bias. Additionally or alternatively, theassembly designer may choose to employ DLP(s) with greater surface areaand/or an increased number of DLP(s) to increase the engagement with theborehole wall in response to a deviation bias.

In certain embodiments, the directional driller may choose to alter therotary mode rotate speed, or the flow rate to fine tune the response ofthe assembly to a deviation bias. If the measurement-while-drillingreadings indicate to the directional driller that the DLP system is notfully providing restorative force in response to deviation bias, thenchanges in rotary speed or flow rate may better position the engagementof the DLP(s) with the borehole wall.

The technology of this application may be deployed across the range ofavailable bend housing directional motor configurations including forinstance high speed, low torque motors, low speed high torque motors,high bend angle or low bend angle housings, or standard or short bit tobend.

Although the technology has been described in language that is specificto certain structures and materials, it is to be understood that theinvention defined in the appended claims is not necessarily limited tothe specific structures and materials described. Rather, the specificaspects are described as forms of implementing the claimed invention.Because many embodiments of the invention can be practiced withoutdeparting from the spirit and scope of the invention, the inventionresides in the claims hereinafter appended. Unless otherwise indicated,all numbers or expressions, such as those expressing dimensions,physical characteristics, etc. used in the specification (other than theclaims) are understood as modified in all instances by the term“approximately.” At the very least, and not as an attempt to limit theapplication of the doctrine of equivalents to the claims, each numericalparameter recited in the specification or claims which is modified bythe term “approximately” should at least be construed in light of thenumber of recited significant digits and by applying ordinary roundingtechniques. Moreover, all ranges disclosed herein are to be understoodto encompass and provide support for claims that recite any and allsubranges or any and all individual values subsumed therein. Forexample, a stated range of 1 to 10 should be considered to include andprovide support for claims that recite any and all subranges orindividual values that are between and/or inclusive of the minimum valueof 1 and the maximum value of 10; that is, all subranges beginning witha minimum value of 1 or more and ending with a maximum value of 10 orless (e.g., 5.5 to 10, 2.34 to 3.56, and so forth) or any values from 1to 10 (e.g., 3, 5.8, 9.9994, and so forth).

What is claimed is:
 1. An apparatus configured to attach to a drillstring of a drilling assembly, the apparatus comprising, a bent housingincluding a lower mandrel section configured to accept a drill bit, thelower mandrel section including at least one camming surface; and atleast one mandrel-activated dynamic pad mounted generally on a bend sideof the bent housing proximal the lower mandrel section and distal a bendof the bent housing, the at least one mandrel-activated dynamic padbeing configured to extend out at least to an extent equal to or greaterthan a diameter of the drill bit, and the at least one mandrel-activateddynamic pad capable of exerting a restorative force to the drillingassembly when the drilling assembly experiences a deviation bias.
 2. Theapparatus of claim 1 further comprising at least one dynamic pad blade,each dynamic pad blade being situated around an outer periphery of acorresponding dynamic pad.
 3. The apparatus of claim 1 furthercomprising two or more dynamic pad blades, each dynamic pad bladeincorporating at least one dynamic pad.
 4. A method comprising:configuring a bent housing of a directional drilling assembly to includean extensible, mandrel-driven dynamic pad, the dynamic pad having anextended length capable of engaging a wall of a rotary-drilled well;drilling in a slide mode or a rotary mode with the directional drillingassembly until a chosen path is achieved; and drilling ahead in therotary mode with the dynamic pad engaging the wall of the rotary-drilledwell and supplying a restoration force to the directional drillingassembly when the directional drilling assembly is biased by a deviationbias.
 5. The method of claim 4 further comprising: employing ameasurement assembly to verify course holding of the directionaldrilling assembly during drilling.
 6. The method of claim 5 furthercomprising: employing a slide correction to return the directionaldrilling assembly to the chosen path following a failure of therestoration force to filly overcome the deviation bias.
 7. The method ofclaim 4 further comprising: measuring a location of the directionaldrilling assembly in the rotary-drilled well to verify a failure tofully overcome the deviation bias; altering an operating parameter toalter a cycle or a location of the engagement of the dynamic pad withthe wall of the rotary-drilled well; and drilling ahead a specifieddistance and then remeasuring the location of the directional drillingassembly in the rotary-drilled well to determine if the alteration ofthe operating parameter improved effectiveness of the restoration force.8. The method of claim 7 further comprising: adjusting the operatingparameter until an improved response to the deviation bias is obtained;performing a slide correction to return to the chosen path; and uponreturning to the chosen path, drilling ahead in the rotary mode.
 9. Themethod of claim 7 wherein the operating parameter is a rotary speed ofthe mandrel or a flow rate of the directional drilling assembly.
 10. Anapparatus for a drilling assembly, the apparatus comprising: a drill bithaving at least one cutting structure for forming a hole, the drill bitbeing connected to a distal end of a drive shaft; a housing thatencircles at least a portion of the drive shaft, the housing including aproximal segment and a distal segment separated from the proximalsegment by a bend; a recess formed in the distal segment along a bendside of the housing; and a pad positioned within the recess, the padbeing configured to move from a retracted position to an extendedposition in which the pad contacts a wall of the hole to produce arestorative force responsive to the drilling assembly being subjected toa deviation force that alters a drilling path of the drill bit.
 11. Theapparatus of claim 10 further comprising: a mandrel connected to adistal end of the second segment of the housing, the mandrel including acavity for receiving the drill bit.
 12. The apparatus of claim 11wherein the mandrel drives the pad from the retracted position to theextended position.
 13. The apparatus of claim 11 wherein the pad isconfigured to move from the retracted position to the extended positionand then back to the retracted position at least once per revolution ofthe mandrel.
 14. The apparatus of claim 11 wherein the pad is configuredto move from the retracted position to the extended position and thenback to the retracted position at least four times per revolution of themandrel.
 15. The apparatus of claim 10 wherein when the pad is in theextended position, a surface of the pad extends past a diameter of thedrill bit.
 16. The apparatus of claim 10 wherein the pad is one ofmultiple pads, and wherein each pad is positioned within a separaterecess formed in the distal segment of the housing.
 17. The apparatus ofclaim 16 wherein each pad of the multiple pads is configured toindependently move from the retracted position to the extended positionto produce a separate restorative force.
 18. The apparatus of claim 10wherein the recess is formed in a blade that extends outward from anouter perimeter of the distal segment of the housing.
 19. The apparatusof claim 10 wherein the restorative force is sufficient to counter thedeviation force, thereby causing the drill bit to return to the drillingpath.
 20. The apparatus of claim 10 wherein a location of the contact ofthe wall by the pad is based on rotational speed of the housing, rotaryspeed, flow rate, or any combination thereof